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CORPORATE PRESENTATIONFEBRUARY 2020

TSX: YGR

FEBRUARY 2020| PG 2yangarra resources ltd. (Refer to end of presentation for slide notes & advisories)

20+ yearsInventory

Environmentally & socially responsible allocator of capital that focuses on full-cycle returns for shareholders by generating positive net-income earnings in the energy sector• Sept 30 YTD 2019 EPS of $0.42 vs. $0.23 full-year 2018• Trailing 12-month ROCE of 13%• Trailing 12-month ROE of 17%

2019 in review:• Completion of ~$30mm of infrastructure• Land accumulation substantially done• Ongoing completions refinement puts go-forward capital program back on track• Abandonment of wells, emissions reductions, and water recycling

Sustainable go-forward plan has Yangarra spending less than cash flow• Incremental free cash flow deployed to debt repayment (target net debt of $150-160mm)• ~35% corporate decline managed by full-cycle capital efficiency of ~$15,000/boed• Sustaining capex of ~$68mm at 13,000 boe/d requires ~C$48 Ed. Par & ~$C1.50/gj AECO (currently

~C$56 & ~C$1.60)

Share price performance lags actual business performance but management focused on creating long-term shareholder value

YANGARRA HIGHLIGHTSTRANSFORMATIVE 2019 SETS THE STAGE FOR 2020 ONWARDS

Current Price: $1.102020E CFPS: $1.26

2020E EV/DACF: ~2.5X

Current Price: $1.10Proved NAV: $10.66

Current Price: $1.10PDP+PNP NAV: $3.08

369 gross locations booked

FULLY-FUNDED INVESTMENT VEHICLE TRADING AT COMPELLING VALUATION METRICS


Additional Information

Basic Shares mm 85.4 15% Insider Ownership

Options mm 8.5 $4.34 Weighted Average Ex. Price

Fully Diluted mm 93.9 22% Total Insider Ownership

Market Capital ization mm $93.9 $1.10 Feb 4 2020

Q3 2019 Adj. Net Debt mm $185.8 $225.0 Total Credit Facility

Enterprise Value mm $279.7

CORPORATE SNAPSHOTWELL CAPITALIZED, STRONG INSIDER OWNERSHIP & A DEFINED RESOURCE BASE

CONCENTRATED HALO CARDIUM PLAYER Dominant land footprint with infrastructure in place

to double production with minimal future infrastructure spend

~80 wells drilled in halo Cardium since August 2016 1,000+ net locations remain

CARDIUM LAND POSITIONCAPITALIZATION SUMMARY

2019E BUDGET

YE 2019 RESERVES

Q3 Production boe/d 12,724 2019 Est. boe/d 12,550

Q3 CAPEX mm $26.6 2019E Capital mm 121

Q3 FFO mm $19.1 # of 2019 wells D&C 17

2020E Capital mm $105.0 2020E Range boe/d 14,000-15,000

# of 2020 wells planned 24

(Plus 3 dri l led at year-end)

2019 2018 2019 2018

% Change % Change

Proved Dev. (PDP) 25.5 23.4 9.0% 414 393 5.3%

Total Proved 85.6 75.5 13.4% 1112 1119 -0.6%

Proved + Probable 145.6 126.3 15.3% 1669 1686 -1.0%

(mmboe) ($mm)

PV10 values impacted by change in price deck forecast


GUIDING PRINCIPLESEMPHASIS ON LONG-TERM RETURNS, MITIGATE SHORT-TERM VOLATILITY

CONTINUOUSIMPROVEMENT

Yangarra is an outcome of strategic decision making, large & small in the past four years Early 2019 was characterized by a necessary spend on facilities capex & a completions

approach that resulted in cost-savings but impacted initial rates; go-forward plans will bear the fruit of learning from 2019 challenges

RISK MITIGATION

Pro-active capital budgeting mitigates commodity price volatility• FFO to capex breakeven at ~$1.75/gj AECO & ~C$61 Ed. Par to fund $105mm capex

• Sustaining FFO to capex (13,000 boe/d) at ~$1.50/gj AECO & ~C$48 Ed. Par

Operational (drilling & completions) & geological risks mitigated by growing database

OPERATIONALFOCUS

Be experts in core area of operations Meticulously concentrate on cost structure Leverage off capital spent to date; go-forward focus on low-risk step-out drilling

LONG-TERM DECISIONMAKING

Addressing short-term market concerns weakens long-term business plan Top-down driven decision making by focusing on full-cycle rates of return Bottom-up approach drives Yangarra outputs on capital, growth, and share buybacks Full-cycle model that shows Yangarra becoming a sustainable ~25,000 boe/d producer

(“plateau production”), driven by unique Yangarra characteristics:• Capital efficiencies offset decline profile

• Quality of tier one inventory with in-place infrastructure drives future returns

• Go-forward sustainable capital program mitigates balance sheet risk as free cash flow pays down debt


PER SHARE NET-ASSET-VALUES SIGNIFICANTLY LAG SHARE PRICEDESPITE 2019 CHALLENGES, NAVPS VALUES RELATIVELY UNCHANGED

Market disconnect between NAVPS and share price belies underlying value of sustainable business plan• Trading at 0.36x PDP+PNP NAV based on independent

reserve report• Trading at 0.10x Proved NAV

Market currently discounting WTI price of ~US$43 in current Yangarra market price on a PDP basis

Market currently discounting WTI price of ~US$20 in current Yangarra market price on a Proved basis

YEARLY RESERVES GROWTH & SHARE PRICE PERFORMANCE

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PDP/PNP NAV10 per share Proved NAV10 per share2P NAV10 per share YGR Share Price

FORECAST EDMONTON PAR PRICE TO ACHIEVE PV10 RESERVE VALUE EQUIVALENT TO EV

Implied Ed. Par

Implied WTI US$

Current WTI U$

YGR Price $1.10 PDP* $52 $43 $52Mkt. Cap $94EV $280 Proved* $22 $20 $52* Assumes CAD/USD FX 1.35, AECO $2.10/mcf, and US$4.00 Diff.


2019 F&D costs effected lower performance on 15-ton completion wells; go-forward F&D costs should trend down as results from new wells drilled post August 2019 highlights impact of 20-ton completions:• PDP recycle ratio of 1.2x, PDP F&D $18.10, 2019E netback $22.35 (2018 netback $27.30)• Proved recycle ratio of 2.1x, proved F&D $10.74• 2P recycle ratio of 3.3x, 2P F&D $6.86

Facilities capex was a material portion of Yangarra’s 2019 capital program (~$30mm), excluding this:• PDP F&D costs of $13.67, 1.6x recycle ratio• Proved F&D costs of $8.71, 2.6x recycle ratio• 2P F&D costs of $5.61, 4.0x recycle ratio

RESERVES VOLUME GROWTH PER SHAREONE-TIME SPEND ON INFRASTRUCTURE IMPACTED 2019 F&D COSTS

YEARLY RESERVES GROWTH (MMBOE & PER SHARE) F&D COSTS

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2P Proved Operating Netback


PRUDENT LEVERAGE BALANCED AGAINST LONG-TERM RETURN ON CAPITALIMPROVING BUSINESS MODEL DRIVING LONG-TERM RETURN ON CAPITAL EMPLOYED

BALANCE SHEET EFFICIENCY1,2,3 RETURN ON CAPITAL EMPLOYED VS. FDC

CAPITAL EFFICIENCY DRIVING DOWN LEVERAGE

Absolute debt levels crept up in 2019, especially in the first quarter, but relative debt leverage (per boed) did not materially change

Given 2020 guidance, absolute debt levels should decrease, predicated on commodity prices

RETURN ON CAPITAL EMPLOYED DRIVING DECISIONS

Yangarra’s ROCE competes with the best Canadian plays and U.S. plays such as the Permian

Reserve bookings increasingly aligned with cash flow, balance sheet, and capital spending• Proved FDC increased to $429mm from $392mm• 2P FDC increased to $650mm from $607mm• FDC financeable with future FFO (don’t require external capital)

1) Debt is equal to year-end net adjusted debt for the respective year2) Trailing CF is FFO for the respective year (i.e. 2018 YE Adj. net debt divided by 2018 FFO)3) Forward CF is FFO for the next respective year (i.e. 2018 YE Adj. net debt divided by 2019E FFO)

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Proved FDC/CF 2P FDC/CF ROCE

2019E ROCE is trailing twelve months as of Sept 30, 2019


LEADERSHIPEXPERIENCED & GEARED FOR DEVELOPMENT

INSIDER OWNERSHIP BOTH AT THE MANAGEMENT LEVEL AND THE BOARD LEVEL PROVIDES STRONG ALIGNMENT WITH SHAREHOLDERS

MANAGEMENT TEAM BOARD OF DIRECTORS

Gordon Bowerman - President of Cove Resources Ltd.Chairman - 50+ years of oil & gas experience

Neil Mackenzie - Director at various public companies- Partner at Blackstone Fluids

Robert Weir - President of Weir Resource Management Ltd.

Ted Morton - Former Albertan & Canadian politician; Held Energy, Finance, Enterprise, and Sustainable Resources Minister positions

Jim Evaskevich - See bio in management team.

Jim Evaskevich - 30+ years of extensive executive experiencePresident & CEO - Strong field & drilling operational background

Lorne Simpson, B.Sc., C.E.T. - 30+ years of experience in oil & gasVP Operations - Drilling operations

Randall Faminow - 30+ years of experience in oil & gasVP Land - Negotiations in acquisitions and divestments

James Glessing, CA - 18+ years of oil & gas accounting experienceChief Financial Officer - Ex-controller & CFO at various energy firms

- Articled at Deloitte

Gurdeep Gill, CFA - 18+ years of experience in capital marketsVP Business Development - Head of investment banking at AltaCorp

Trish Olynyk - 20+ years of experience in oil & gasVP Finance - Controller at Yangarra since 2005


0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0

Haynesville Shale - TXEagle Ford Shale - Gas-Condensate

Eagle Ford Oil - WestNotikewin Sundance

Montney GroundbirchPowder River Basin - Turner

Haynesville Shale - LADuvernay Liquids Rich

Eagle Ford Oil - EastDJ Basin NiobraraSTACK Woodford

Wilrich EdsonSTACK Meramec

Cardium GasDelaware Wolfcamp A

Montney Dawson UpperN. Midland Lower SpraberrySW Marcellus - Liquids Rich

N. Midland Wolfcamp BMontney Tower Liquids Rich

NE Marcellus - DryMontney Greater UmbachCardium Willesden Green

Montney Pouce CoupeNorth Dakota Bakken/Three Forks

Austin ChalkMontney Glacier

Cardium Pembina WestConventional Heavy Oil Hz

Eagle Ford Oil - West (Top Quartile)Mississippian Frac Midale

East Shale Duvernay Oil Top QuartileN. Midland Wolfcamp A

Viking Hz. AlbertaBakken Hz. (<1,700 m)

Montney Elmworth/WapitiShaunavon Hz.

Cardium Oil FerrierMontney Nig/Beg

Charlie LakeViking Hz. Dodsland ERH

North Dakota Bakken/Three Forks (Top Quartile)Montney Pipestone

Montney Inga/FireweedMontney Karr

Eagle Ford Oil - East (Top Quartile)N. Midland Wolfcamp A (Top Quartile)

Montney KakwaDelaware Wolfcamp A (Top Quartile)

Montney GundyMontney Dawson Lower

Mississippian ConventionalClearwater Marten Hills/Nipisi

Oil Plays Median of 2.0 Years

Natural Gas Median of 2.3 Years

TECH

NO

LOG

ICALS HIFT

2009 TO 2014/15 MSF horizontal wells unlocked

halo Cardium

CARDIUM EVOLUTIONCARDIUM PAYOUTS COMPETE WELL WITH OTHER NORTH AMERICAN PLAYS; CHEDDERVILLE STACKS UP EVEN BETTER

1950’S TO 2009 Prolific Cardium sands exploited

by vertical wells Conventional pool boundaries

well understood by industry

CONVENTIONAL CARDIUM HALO CARDIUM

Chedder (2-mile): 11 monthsCow Lake (2-mile): 16 months

CARDIUM RELATIVE TO NORTH AMERICA

RELATIVE PLAY COMPARISON

Yangarra payouts in new core areas exceed industry expectations due to bioturbated zone & Yangarra’s cost structure

North American Oil and Natural Gas PlaysHalf-Cycle Payout Period

Source: Peters & Co. Limited estimates based on US$60/B WTI, US$2.40/Mcf NYMEX and C$2.00/Mcf AECO prices.


UPPER CARDIUM OOIP TARGET/SECTION~2-5 mmbbl OOIP~6-20 mmboe OBOEIP

PLUS BIOTURBATED TARGET/SECTION~4.5-6 mmbbl OOIP~12-18 mmboe OBOEIP

TOTAL TARGET~7.5-10 mmbbl OOIP~18-38 mmboe OBOEIP

YGR BIOTURBATED VIEW

Actual core analysis (by YGR & Weatherford) shows porosity

increases to 4-6%Materially increasing OOIP/OBOEIP

target estimates

CARDIUM REVOLUTIONBIOTURBATED ZONE CONTRIBUTES MATERIALLY TO HALO CARDIUM POTENTIAL

ORIGINAL LOG & BIOTURBATED CORE EXAMPLE

Yangarra approach:• Cemented liners• Sliding sleeves• Extended reach wells

Frack into bioturbated zone to access bioturbated zone & upper Cardium

Upper2.5-4.0m

Lower1.5-3.0m

Bioturb.3.0-7.0m

Net Pay

NEW FRAC PLANE

New Well Path

IT’S ALL ABOUT OOIP/OBOEIP

Willesden Green T41-R6W/5

Upper SandCore analysis

Porosity 10-15%

BioturbatedLog Porosity 3%

TECH

NO

LOG

YPRO

GRESSIO

N

Old Well Path

Deeper well path allows YGR to access significantly more OBOEIP

Gas-charge drives higher oil and NGLs recoveries (see type curve)


CURRENT COW LAKE & CHEDDERVILLE

In sub US$60 WTI environment, pursue high-GOR areas, like Cow Lake & Chedderville• High-rate wells drive excellent IRRs despite higher gas rates

As WTI approaches US$65, deploy capital in low-GOR areas that have lower-rates but higher oil cuts

2020 PLANS IN FOCUSEXPAND ON SUCCESS AT COW LAKE & CHEDDERVILLE

Proving the thesis: Pre-October 2018 wells exceeded corporate risked

type curve 20-ton outperforming 15-ton based on initial results;

more production history required

Acquired 52.5 sections with 46 mmcf/d gas handling capacity in area

PRE-2018 LANDS

COW LAKE & CHEDDER RESULTS ON 20-TON FRACS VS. 15-TON FRACS

Normalized to 1.5 mile


Gross Net WITotal Sections 165.5 147.8Total Acres 105,920 94,592 89%

One-mile locations 1,137 1,003

Per section count varies with GORs. Low GOR areas have well density; high GOR areas have

lower drilling density

OOIP/Section~18-38 mmboe(~7.5-10 mmbl

OOIP)

Well Recovery Factor

~15-16%

Section Recovery Factor~12%

GEOLOGICAL MAPPING, RESERVOIR PARAMETERS & ECONOMIC TYPE CURVE KEY TO INVENTORY COUNT

Recoveries for unconventional wells different from conventional vertical Cardium• Yangarra and its third-party reserve engineers forecast a horizontal well will drain up to ~64 acres due to tight reservoir parameters• Empirical evidence suggests minimal communication between horizontal wells at 150m (490 feet) spacing, other than natural

fracturing

Inventory count evolves based on well performance & technological progress

CARDIUM INVENTORYDISCIPLINED APPROACH DRIVES LAND ACQUISITION STRATEGY

ONE WELL

OBOEIP/Section~18-38 mmboe(~7.5-10 mmbl

OOIP)


~15-16%

Section RecoveryFactor~1.5%

4 WELLS / SECTION

OOIP/Section~18-38 mmboe(~7.5-10 mmbl

OOIP)


~15-16%

Section Recovery Factor~6%

8 WELLS / SECTION

LAND & INVENTORY SUMMARY ILLUSTRATIVE SECTION EXPLOITATION STRATEGY EXPLOITATION STRATEGY

Sub US$60 WTI, high-rate, high GOR wells meet internal IRR thresholds

Maintain optionality on low-GOR, low-rate wells with commodity price upside

Increase in locations due to land acquisition activity


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1.5 MileDCET $mm $3.75 % OilIP30 - Oil bbl/d 241 62%IP30 - BOE boe/d 390IP90 - Oil bbl/d 201 52%IP90 - BOE boe/d 383IP365 - Oil bbl/d 127 36%IP 365 - BOE boe/d 348Capital Eff. (1st year) $/boe/d $10,776 % Oil % NGLs % GasEUR mboe 420 31% 17% 52%F&D (Half Cycle) $/boe $8.92

Price Sensitivity: WTI (USD/bbl) $40 $50 $55 $60IRR % 36% 70% 93% 120%NPV10% $mm $1.7 $3.1 $3.8 $4.4Payback months 26.0 16.0 13.0 11.0Recycle Ratio x 2.1x 2.7x 3.1x 3.4x*Above is a weighted average type curve encompassing 1, 1.5, 2.0 mile locations

The above EUR will not match the "Section Analysis" on the Inventory slide.

Average Weighted Risked Type Curve

EURs & IPs will vary across land base

RISKED ECONOMICSAPPLYING 20% RISK FACTOR TO PREVIOUS UN-RISKED TYPE CURVES

Type curve as presented reflects 20% risk factor as per capital budget planning process

RISKED WEIGHTED-AVERAGE TYPE CURVE PRODUCTION PROFILE

RISKED WEIGHTED-AVERAGE TYPE CURVE CUMULATIVE PRODUCTION

RISKED WEIGHTED-AVERAGE TYPE CURVE ASSUMPTIONS

NGLs Yield:55 bbl/mmcf (life of well)


CONVENTIONAL THINKING

Build massive contiguous land base Drive down costs by overcapitalizing

infrastructure (oil pipelines & gas-processing)

YANGARRA: LOOK FORWARD NOT BACKWARDS

Create flexible production environment to target top-tier acreage

Handle all gas Truck emulsion

RESULTS! Blending: higher product pricing Trucking: Maximize revenue per bbl by

exercising optionality to multiple egress points (Central AB to SK to USA)

Lower op costs (<$7.00 per boe)

PRODUCTION LOGISTICSINSTRUMENTAL IN CREATING SUSTAINABLE LOW-OP COST STRUCTURE

YANGARRA INFRASTRUCTURE

Yangarra Facilities

Operate >97% of production Maximize gas handling, minimize 3rd party handling Maximize trucking efforts, minimize oil pipelines 18 emulsion hauling trucks in Yangarra fleet, recently added wireline


Yangarra focuses on creating long-term shareholder value through financial discipline while minimizing Yangarra’s environmental footprint and by operating in a safe & diverse culture

ENVIRONMENT SOCIAL GOVERNANCE STRATEGYPRAGMATIC APPROACH ADDRESSES INVESTOR CONCERNS WHILE DRIVING RETURNS

Environment

Methane / C02 Fugitive emissions

Flaring

Baseline study complete on track for 55% reduction

Recently revised completions to reduce flaring by 90%; reducing completions costs by ~10%

Water Frack water / Produced water Completions designed to recycle frack water and produced water to next frack; company owned trucks ideal for this strategy

ARO / LLR Industry leading 13.17 LLR & $16.7 MM undiscounted ARO

Drilled 300 wells since inception, 120 have been abandoned; clean up as we go

Social GenderPaySafetyCommunity

AgnosticAgnosticTop DecileDonations >$200k / Support local initiatives

Governance Shareholder alignmentFiscalDiversity – Executives

– Directors

High insider ownership is best alignment methodFull cycle capital allocationRecent appointments Policy in place


APPENDIX

RISK MANAGEMENT, ANALYST COVERAGE, PRESENTATION FOOTNOTES & FORWARD LOOKING STATEMENTS


ANALYST COVERAGEBROADLY COVERED BY THE STREET

Acumen Capital Finance Partners Ltd.Trevor [email protected](403) 410-6842

AltaCorp Capital Inc.Patrick O’[email protected](403) 539-8615

Canaccord GenuityAnthony [email protected](403) 691-7807

CIBC World MarketsDave [email protected] (403) 216-3401

Cormark Securities Inc. Amir Arif, [email protected](403) 750-7200

Industrial Alliance Securities Inc.Michael Charlton [email protected](403) 705-4978

Laurentian Bank SecuritiesTodd Kepler, [email protected](403) 453-2909

National Bank FinancialJohn [email protected](403) 441-0955

Paradigm Capital Inc.Transitioning Coverage

Peters & CoDan [email protected](403) 261-2215

Raymond James Ltd.Jeremy McCrea, [email protected](403) 509-0518

TD Securities Ltd.Sean [email protected](403) 299-3272


Slide 2: ROCE: Trailing 12-month EBIT as at September 30, 2019 divided by (Total Assets less Current Liabilities); ROE: Trailing 12-month net income as at September 30, 2019 divided by Shareholders Equity; 2020E CFPS: Consensus FFO estimate as at February 4, 2020; NAV = NPV10 Reserve Value less adjusted Net Debt and excludes undeveloped land value, effective as at December 31, 2019 based on the reserve report prepared by Deloitte LLP, independent petroleum engineers (the “Reserves Report”); Sustaining capex calculation: 13,000 boe/d times 35% decline times $15,000 capital efficiency; Decline rates & capital efficiency are internal management estimates based on type curves and modelling

Slide 3: FFO: see definition on slide 19 Slide 4: Sustaining capex calculation: 13,000 boe/d times 35% decline times $15,000 capital efficiency; Decline rates & capital efficiency are

internal management estimates based on type curves and modelling; FFO to $105mm capex based on mid-point of production guidance Slide 5: NAV = see note for Slide 2; EV: assumes September 30, 2019 net debt; Reserve value equivalency at $280mm calculated using inputs

from the Reserve Report and Val Nav software, assumes flat pricing and are prepared by a Qualified Reserves Evaluator employed internally by the Company and follows good engineering practices as outlined in the COGE Handbook

Slide 7: ROCE = see note for Slide 2; definitions for FFO Slide 9: Payout chart as provided by Peters & Co. Limited (“Peters”); Chedder & Cow Lake payouts calculated using Peters assumptions Slide 12: Inventory is an internal management estimate Slide 13: Flat commodity price assumptions: Ed. Par differential US$4.00, F/X 0.746, AECO C$2.00/mcf; Operating cost of $7.00/boe including

transportation; Type curves are based an inventory weighted average type curve for each area using both 1.0 mile and 2.0 mile data. Type curves are prepared by a Qualified Reserves Evaluator employed internally by the Company and follows good engineering practices as outlined in the COGE Handbook; the type curves are estimates based on forecast assumptions of decline variables using widely accepted industry economics programs which include a decline curve tool.

Slides 10, 12, 15: OOIP & OBOEIP data are provided to illustrate how the Company targets land acquisition and drilling opportunities and are not actual amounts calculated by the Company. However, the OOIP & OBOEIP estimates are prepared by a Qualified Reserves Evaluator employed internally by the Company and follows good engineering practices as outlined in the COGE Handbook. Reservoir parameters are assumed for sections without production to calculate “in-place” estimates; where well(s) are drilled in a section, reservoir parameters are determined and used to calculate “in-place” values. OOIP estimates are provided in conjunction with OBOEIP estimates whereby OBOEIP equals OOIP plus gas in place and liquids is calculated using 55 bbls/mmcf. OOIP & OBOEIP estimates are a combination of discovered and undiscovered quantities and are highly dependent upon if there are existing wells in specific sections.

Additional Information/Terminology: Gas converted at 6 mcf : 1 barrel of equivalent basis (BOE) OOIP: original oil in place; OBOEIP: original barrels of equivalent in place

PRESENTATION FOOTNOTESFEBRUARY 2020


Non–IFRS and Additional IFRS Measures This document contains “funds flow from (used in) operations”, which is an additional IFRS measure. The Company uses funds flow generated from (used in) operations as a key measure to demonstrate the Company’s ability to generate funds to repay debt and fund future capital investment. This document also contains the terms “net debt or adjusted working capital (deficit)” and “netbacks”, which are non-IFRS financial measures. The Company uses these measures to help evaluate its performance. These non-IFRS financial measures do not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures presented by other issuers. Funds flow from operationsYangarra’s determination of funds flow from operations and funds flow from operations per share may not be comparable to that reported by other companies. Management uses funds flow from operations to analyze operating performance and leverage and considers funds flow from operations to be a key measure as it demonstrates the Company’s ability to generate cash necessary to fund future capital investments and to repay debt, if applicable. Funds flow from operations is calculated using cash from operating activities before changes in non-cash working capital and decommissioning costs incurred. Yangarra presents funds flow from operations per share whereby per share amounts are calculated using weighted average shares outstanding consistent with the calculation of income per share.NetbacksThe Company considers corporate netbacks to be a key measure as they demonstrate Yangarra’s profitability relative to current commodity prices. Corporate netbacks are comprised of operating, field operating, funds flow from operations and net income / (loss) netbacks. Operating netback is calculated as the average sales price of its commodities (including realized gains on financial instruments) and then subtracts royalties, operating costs and transportation expenses. Field operating netback subtracts the realized gains on financial instruments, Funds flow from operations netback starts with the operating netback and further deducts general and administrative costs, finance expense and adds finance income. To calculate the net income (loss) netback, Yangarra takes the funds flow netback and deducts share-based compensation expense as well as depletion and depreciation charges, accretion expense, unrealized gains on financial instruments, any impairment or exploration and evaluation expense and deferred income taxes. There is no IFRS measure that is reasonably comparable to netbacks. Funds flow from operations margins and Operating marginsAre calculated as the ratio of Funds flow from operations netbacks to sales price and operating netback to sales price.Adjusted Net debtAdjusted net debt, which represent current assets less current liabilities, excluding current derivative financial instruments, are used to assess efficiency, liquidity and the general financial strength of the Company. There is no IFRS measure that is reasonably comparable to net debt or adjusted working capital (deficit). Adjusted earnings before interest, taxes, depletion & depreciation, amortizationAdjusted earnings before interest, taxes, depletion & depreciation, amortization (“Adjusted EBITDA”) which represents EBITDA, excluding changes in derivative financial instruments are used to assess efficiency, liquidity and the general financial strength of the Company. Working Capital deficit (surplus)Working capital deficit (surplus) is the total of current assets less the total of current liabilities and is used to assess efficiency, liquidity and the general financial strength of the CompanyReconciliations for the above Non–IFRS and Additional IFRS Measures are presented in the Company’s latest MD&A

PRESENTATION FOOTNOTESFEBRUARY 2020


This presentation contains a summary of management's assessment of results and should be read in conjunction with the Consolidated Financial Statements andrelated Management's Discussion and Analysis for the year ended December 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. Thereader 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 futureplans and operations, the planning and development of certain prospects, the 2019 Capital Program and the Company's proposed exploration and developmentactivities and the timing thereof, including the amount and allocation of capital expenditures, the number and types of wells to be drilled and brought onproduction and the timing thereof, estimates of total and net capital expenditures, and the focus of, the objectives of and the anticipated results from the 2019Capital Program, production estimates, reserve estimates, productive capacity and economics of new wells, undeveloped land holdings and values, capitalexpenditures and the timing and allocation thereof (including the number, location and costs of planned wells), the total future capital required to bringundeveloped proved and probable reserves onto production, and expected production growth, may constitute forward-looking statements under applicablesecurities laws and necessarily involve substantial known and unknown risks and uncertainties. With respect to the Company's 2019 production guidance, the keyassumptions are that: the 2019 Capital Program will be carried out as currently contemplated; no unexpected outages occur in the infrastructure that theCompany relies on to produce its wells and that any transportation service curtailments or unplanned outages that occur will be short in duration or otherwiseinsignificant; existing wells continue to meet production expectations; and future wells scheduled to come on production meet timing, production and capitalexpenditure 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, currencyfluctuations, 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 marketvolatility, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources, theimpact of general economic conditions in Canada, the United States and overseas, industry conditions, changes in laws and regulations (including the adoption ofnew environmental laws and regulations) and changes in how they are interpreted and enforced, increased competition, fluctuations in foreign exchange orinterest rates and market valuations of companies with respect to announced transactions and the final valuations thereof. Readers are cautioned that theforegoing list of factors is not exhaustive. The Company's actual results, performance or achievement could differ materially from those expressed in, or impliedby, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements willtranspire 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 onthese and other factors that could affect the Company's operations and financial results are included in reports on file with Canadian securities regulatoryauthorities and may be accessed through the SEDAR website (www.sedar.com) or the Company's website (www.yangarra.ca), including the Company's MD&A forthe year ended December 31, 2018.

FORWARD LOOKING STATEMENTS


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 updatepublicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may berequired by applicable securities laws. Certain information contained herein is based on, or derived from, information provided by independent third-partysources. The Company believes that such information is accurate and that the sources from which it has been obtained are reliable. The Company cannotguarantee the accuracy of such information, however, and has not independently verified the assumptions on which such information is based. The Companydoes 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 ofoperations, cash flow, capital expenditures, net debt and components thereof, all of which are subject to the same assumptions, risk factors, limitations, andqualifications 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 thepurpose of providing information about management's current expectations and plans relating to the future, including with respect to the Company's ability tofund its expenditures. The Company disclaims any intention or obligation to update or revise any forward-looking statements or FOFI contained in thispresentation, whether as a result of new information, future events or otherwise, unless required pursuant to applicable securities law. Readers are cautionedthat the forward-looking statements and FOFI contained in this presentation should not be used for purposes other than for which it is disclosed herein. Theforward-looking statements and FOFI contained in this presentation are expressly qualified by this cautionary statement.

FORWARD LOOKING STATEMENTS(CONT.)


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 nothave standardized meanings prescribed by International Financial Reporting Standards (“IFRS”) and therefore should not be considered in isolation. Thesereported amounts and their underlying calculations are not necessarily comparable or calculated in an identical manner to a similarly titled measure of othercompanies where similar terminology is used. Where these measures are used they should be given careful consideration by the reader. These measures havebeen described and presented in this presentation in order to provide shareholders and potential investors with additional information regarding the Company'sliquidity and its ability to generate funds to finance its operations. Netback denotes petroleum and natural gas revenue and realized gains or losses on financialinstruments less royalty expenses, operating expenses and transportation and marketing expenses calculated on a per boe basis. Cash flow should not beconsidered an alternative to, or more meaningful than, cash provided by operating, investing and financing activities or net earnings as determined in accordancewith 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 togenerate cash flow to fund capital expenditures and repay debt. Included in this presentation are estimates of the Company's 2019 cash flow which are based onvarious assumptions as to production levels, commodity prices and other assumptions, are provided for illustration only and are based on budgets and forecaststhat 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 basedon the capital expenditures and other assumptions described and readers are cautioned that the information may not be appropriate for other purposes. TheCompany uses net debt as a measure to assess its financial position. Net debt includes current liabilities (including the Company's credit facility and excluding thecurrent portion of decommissioning obligations) less current assets (excluding property, plant and equipment, held for sale and risk management contracts).

Certain information provided in this news release may constitute "analogous information" under applicable securities legislation, such as reserve and resourceestimates or the reserves and resources present on the Company's lands, and nearby lands, total production and production-rates from wells drilled by theCompany or other industry participants located in geographical proximity to lands held by the Company. This information is derived from publicly availableinformation sources (as at the date of this news release) that the Company believes are predominantly independent in nature. The Company believes thisinformation 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 theanalogous information was prepared by a qualified reserves evaluator or auditor or in accordance with the Canadian Oil and Gas Evaluation Handbook andtherefore, 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 maynot be representative of actual results of wells anticipated to be drilled or completed by the Company in the future.

FORWARD LOOKING STATEMENTSNON-GAAP MEASURES & ANALOGOUS INFORMATION


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 otherwisestated. 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; thereforeBoe's may be misleading if used in isolation. References to natural gas liquids ("NGLs") in this presentation include condensate, propane, butane and ethane andone 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:"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 quantitiesrecovered will exceed the estimated proved reserves."Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remainingquantities recovered will be greater or less than the sum of the estimated proved plus probable reserves."Developed" reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, thatwould involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production."Developed Producing" reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. Thesereserves 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 withreasonable certainty."Developed Non-Producing" reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in, andthe date of resumption of production is unknown."Undeveloped" reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when comparedto 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.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 ourreserves. 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 meaningsprescribed by GAAP and therefore should not be considered in isolation. These reported amounts and their underlying calculations are not necessarilycomparable or calculated in an identical manner to a similarly titled measure of other companies where similar terminology is used. Where these measures areused they should be given careful consideration by the reader. These measures have been described and presented in this presentation in order to provideshareholders 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 andtransportation and marketing expenses calculated on a per boe basis.

FORWARD LOOKING STATEMENTSRESERVE DEFINITIONS

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