Ridgeback ResourcesCorporate Presentation

October 2019

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Disclaimer – Forward Looking Statements

This presentation may contain "forward-looking statements" within the meaning of applicable securities legislation, including estimates of future production, cash flows andreserves, business plans for drilling and exploration, the estimated amounts and timing of capital expenditures, the assumptions upon which estimates are based and relatedsensitivity analyses, and other expectations, beliefs, plans, objectives, assumptions or statements about future events or performance (often, but not always, using words or phrasessuch as "expects" or "does not expect", "is expected", "anticipates" or "does not anticipate", "plans", "estimated" or "intends", or stating that certain actions, events or results “may","could", "would", "might" or "will" be taken, occur or be achieved). In particular, this presentation contains forward-looking statements pertaining, to the following: estimates ofinfrastructure processing capacity, well costs, payout and IRR estimates. Statements relating to "reserves" are deemed to be forward looking statements, as they involve the impliedassessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably producedin the future. There are numerous uncertainties inherent in estimating crude oil and natural gas reserves and the future cash flow attributed to such reserves. The reserve andassociated cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserverecovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and futureoperating expenses, all of which may vary materially. Actual reserve values may be greater than or less than the estimates provided herein. Unless otherwise noted, reservesreferenced herein are given as at December 31, 2016. Also, estimates of reserves and future net revenue for individual properties may not reflect the same confidence level asestimates and future net revenue for all properties due to the effect of aggregation. All forward-looking statements are based on Ridgeback’s beliefs and assumptions based oninformation available at the time the assumption was made. Ridgeback believes that the expectations reflected in these forward-looking statements are reasonable but no assurancecan be given that these expectations will prove to be correct and such forward-looking statements included in this presentation should not be unduly relied upon. By their nature,such forward-looking statements are subject to a number of risks, uncertainties and assumptions, which could cause actual results or other expectations to differ materially fromthose anticipated, expressed or implied by such statements. Risk factors include: financial risk of marketing reserves at an acceptable price given market conditions; volatility inmarket prices for oil and natural gas; delays in business operations; pipeline restrictions; infrastructure construction schedule delays and cost overruns; blowouts; the risk of carryingout operations with minimal environmental impact; industry conditions including changes in laws and regulations including the adoption of new environmental laws and regulationsand changes in how they are interpreted and enforced; uncertainties associated with estimating oil and natural gas reserves; economic risk of finding and producing reserves at areasonable cost; increased competition for, among other things, capital, acquisitions of reserves and undeveloped lands; competition for and availability of qualified personnel ormanagement; incorrect assessments of the value of acquisitions and exploration and development programs; unexpected geological, technical, drilling, construction and processingproblems; availability of insurance; fluctuations in foreign exchange and interest rates; general economic, market and business conditions; uncertainties associated with regulatoryapprovals; uncertainty of government policy changes; uncertainties associated with credit facilities and counterparty credit risk; and changes in income tax laws, tax laws, crownroyalty rates and incentive programs relating to the oil and gas industry. These risks and uncertainties could cause actual results or other expectations to differ materially from thoseanticipated, expressed or implied by such statements. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certaintyas these are interdependent. Ridgeback assumes no obligation to update forward-looking statements should circumstances or management's estimates or opinions change. Certaininformation contained herein have been prepared by third-party sources. The information provided herein has not been independently audited or verified by the Company.

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AB SK

Corporate Snapshot

Operating & Financial 2017(1) 2018 2019e

Production (boe/d) 21,000 22,808 23,000

Oil & NGL Weighting (%) 71% 75% 74%

Exit December (boe/d) 21,050 25,725 25,700

Net Debt Year-End ($MM) $267 $251 $181(2)

Year End Debt to Adjusted Funds Flow 1.9x 1.2x 0.8x

Operating Netback ($/boe) $24.12 $30.61 $29.65

Adjusted Funds Flow from Operations ($MM) $142 $211 $218(2)

Capital Expenditure ($MM)(4) $111 $175 $148

Free Cash Flow ($MM) $31 $36 $70

1P Reserves(3) (MMBoe) 75 80

2P Reserves(3) (MMBoe) 114 118

Average Corporate Decline Rate ~27%

Large oil-in-place assets with exploitation and

optimization opportunities

~88% operated + ~70% WI in focused

core areas

Repeatable, low-risk growth complemented by

higher-impact drilling opportunities

Light oil weighted asset base

Kaybob Montney

West Pembina Cardium

SE Sask Bakken & Mississippian

Deer MountainSwan Hills

1 2017 operations reflect only 6 months of new management and strategic direction2 Based on 2019 strip pricing , as of August 13, 2019, of WTI $56.98/bbl, US$5.15/bbl Light Oil Differential, AECO $1.53/GJ, and $0.754 CAD/US F/X3 Sproule year-end4 Includes ARO spending

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Strategic Priorities

1) Focus on Value Creation and Capital Efficiency

Spend within cash flow to grow production, reserves, inventory and ideas

Execute on identified, high graded inventory with focus on returns and capital efficiencies

Manage all costs (capital, operating and G&A) and focus on attention to detail

2) Protect the Balance Sheet

Respond quickly to changes in commodity prices

Continue to reduce debt

3) Continue to Grow Ridgeback

Develop current assets

Consolidate interests in core areas and opportunistically acquire assets

Pursue consolidation and other opportunities for liquidity

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2018 Highlights

Average annual production of 22,808 boe/d (75% crude and NGLs); +8% increase year-over-year

2018 year-over-year exit growth of 22%

Crude oil and liquids volumes +19% year-over-year

Achieved production growth spending 83% of cash flow and reducing debt, supporting 2018

production per debt-adjusted share growth of 13%

Adjusted funds flow from operations of $211MM or $2.09/share (basic & diluted); +48% over 2017

Production expenses of $13.61/boe was down 4% year-over-year

2018 G&A reduced to $2.04/boe vs $3.06/boe in 2017, largely due to streamlining through

restructuring

Capital expenditures totaled $193.2MM including ARO and $17.4mm of A&D spending

Spud 66 (56.3 net) wells and made significant infrastructure investment at Kaybob

Replaced 185% of production and added 4 mmboe total proved plus probable reserves

Net debt reduced to ~$251MM, improving year-end D/CF to 1.2x, compared to 1.9x at year-end 2017

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1H 2019 Highlights

Average production of 23,801 boe/d (74% crude and NGLs); 6% increase compared to 1H 2018

Capital expenditures of only $21.2MM in first half

Adjusted funds flow from operations of $122.5MM – 11% higher than 1H 2018 – despite lower

realized crude oil pricing

Operating costs of $12.08/boe – a reduction of $1.75/boe relative to 1H 2018

At June 30, 2019, net debt totalled $150.7MM – reduction of $100.7MM from $251.4MM at

December 31, 2018 – improving debt to cash flow to 0.6 times from 1.2 times at year end 2018

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1H19 2019 Operating Results

Six Months ended June 302019 2018

ProductionCrude oil (bbl/d) 15,225 14,491

NGL (bbl/d) 2,343 2,185

Natural gas (mcf/d) 37,395 34,359

Total (boe/d) 23,801 22,402

Liquids weighting 74% 74%

Average prices (CDN $)

WTI ($/bbl) 76.51 83.59

Crude oil ($/bbl) realized 69.43 76.12

Natural gas ($/mcf) 2.00 1.77

Natural gas liquids ($/bbl) 23.94 36.94

Combined ($/boe) 49.91 55.56

Total with hedging ($/boe) 49.35 52.48

Operating netback ($/boe)(ex hedging) 31.39 34.37

Operating cost ($/boe) 12.08 13.84

Net G&A ($/boe) 1.98 2.01

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1H 2019 Financial Results

Six Months ended June 30

2019($MM)

2018($MM)

Oil & Natural Gas Sales 215,021 225,290

Adjusted Funds Flow from Operations 122,543 110,125

Net Income (loss) 11,924 (6,034)

Capital Expenditures 21,2013 61,863

Net Debt 150,715 220,763

Debt to Annualized Cash Flow 0.61 1.00

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Reserves – YE 2018

CategoryOil & NGLmmbbl)

Gas(bcf)

Total(mmboe)

BT NPV10($MM)

Proved developed producing 31.3 77.3 44.2 850

Proved developed non-producing 1.2 2.9 1.7 26

Proved undeveloped 25.7 50.2 34.1 273

Total proved 58.2 130.5 80.0 1,149

Probable developed producing 9.3 19.0 12.5 192

Probable developed non-producing 0.6 1.4 0.8 12

Probable undeveloped 18.9 35.7 24.8 320

Total probable 28.8 56.1 38.1 525

Total proved plus probable 87.0 186.5 118.1 1,674

2018 development program consisted of 66 gross (56.3 net) wells

PDP reserves = 37% of total P+P

P+PDP reserves = 48% of total P+P

Quality reserve bookings underpin value creation strategy

*Sproule December 31, 2018Numbers may not add due to rounding

Bakken

29%

Mississippian5%Kaybob

5%West Pembina

25%

Brazeau17%

Other Alberta19%

2P Reserves (mmboe)

Bakken38%

Mississippian8%

Kaybob6%

West Pembina

26%

Brazeau8%

Other Alberta14%

2P BT NPV10 ($mm)

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Drilling Inventory

Area

Gross Booked

Locations

NetBooked

Locations

S.E. Saskatchewan – Bakken 298 233

S.E. Saskatchewan – Mississippian 33 26

Cardium 223 156

Deer Mountain – Swan Hills 32 29

Kaybob – Montney 23 23

Other 10 3

Total 619 470

Conventional & unconventional plays in four core areas:

Southeast Saskatchewan:

Bakken

Mississippian

Central Alberta

Cardium and Mannville

Kaybob

Montney

Deer Mountain

Swan Hills

>600 Booked locations ~10 years of drilling inventory

All locations reviewed and ranked by technical team

Unbooked inventory represents an additional~480 gross (~360 net) locations

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Southeast Saskatchewan - Bakken

Light oil-weighted opportunities with low risk, repeatable, infill and delineation drilling

Large Oil in Place: 4.5 mmbbls/sec

Depth: ~1,600m

Oil quality: 40 API sweet

Well spacing: 4-8 wells/sec

Drilling locations: 298 gross (233 net) booked196 gross (149 net) unbooked

2019 DCET capex: $38MM32 gross (24.7 net) wells

Assumptions:

Flat US$60/bbl WTI

$1.56MM DCET cost

IP 120bbl/d (150boe/d)

EUR 60mbbl (70mboe)

2.2 yrs payout

37% IRR Single well, half-cycle economics

Downspacing offers significant long-term

growth potential

SK

SE Sask Bakken

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Southeast Saskatchewan - Mississippian

Large Oil in Place: 5-10 mmbbl/sec

Depth: ~1,300m

Oil quality: 35 API

Well spacing: 150m inter well

Drilling locations: 33 gross (26 net) bookedSignificant unbooked potential

2019 DCET capex: $6MM6 gross (5.5 net) wells

Conventional openhole play offers low-risk development with exploration upside

Assumptions:

Flat US$60/bbl WTI

$1.0MM DCET cost

IP 115bbl/d

EUR 55mbbl

0.9 yr payout

135% IRR Single well, half-cycle economics

Existing company infrastructure allows for

reserve base growth with minimal capital

requirements

SK

SE Sask Mississippian

Ridgeback has gathered considerable data supporting Mississippian

development while exploiting the underlying Bakken

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West Pembina – Cardium

Assumptions:

Flat US$60/bbl WTI

$3.56MM DCET cost

IP 240bbl/d (275boe/d)

EUR 160mbbl (230mboe)

1.9 yrs payout

46% IRR Single well, half cycle economics – 1.5 mile

Extended reach horizontal drilling using advanced

well targeting & frac designs

AB

West Pembina Cardium

Well defined development fairway provides repeatable, low-risk growth

Large Oil in Place: ~5 MMbbl/sec

Depth: ~1,800m

Oil quality: 40 API sweet

Well spacing: 4 wells / sec

Drilling locations: 110 gross (68 net) booked62 gross (48 net) unbooked

2019 DCET capex: $44MM15 gross (12.3 net) wells

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Kaybob - Montney

Significant, 100% working interest land position

Large Oil in Place: 10 MMbbl/sec

Depth: 1,850m

Oil quality: 35-40 API, 1.5% sour

Well spacing: 6 wells / sec

Drilling locations: 23 gross (23 net) booked6 unbooked

2019 DCET capex: $16MM5 gross (5 net) wells

Assumptions:

Flat US$60/bbl WTI

$3.24MM DCET cost

IP 560bbl/d (670boe/d)

EUR 200mbbl (365mboe)

0.8 yrs payout

150% IRR Single well, half cycle economics – 1.5 mile

Geological mapping supports the offsetting Triassic G (Montney) oil

pool extension onto Ridgeback’s lands

KaybobMontney

AB

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Summary

Capital spending within cash flow and managing costs in all aspects of the business

supports value creation and capital efficiencies

Supported by sophisticated, patient, large shareholders

High-quality, focused asset base with large oil-in-place

Low corporate decline underpins production and provides stable cash flow while

executing on business plan

Multi-year drilling inventory supports visibility towards 28,000-30,000 boe/d of

production

Supplement organic growth through consolidation and potential liquidity opportunities

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Leadership Team

Board of Directors

J. Paul Charron Executive Chairman & CEO

Jason Scheir Apollo Management

Jonathan L. Shifke GSO Capital Partners

Michael Tu Apollo Management

ManagementJ. Paul Charron, B.Comm., C.A., C.P.A.Executive Chairman & CEO

CanEra Inc., CanEra Energy Corp., CanEra Resources, Canetic, Acclaim , Ketch

David J. Broshko, B.Comm., C.A., C.P.A., C.Dir.President

CanEra Inc., CanEra Energy Corp., CanEra Resources, Canetic, Acclaim, Paramount

Paul L. Massé, P.Tech. (Eng.)Chief Operating Officer

CanEra Inc., CanEra Energy Corp., CanEra Resources, Canetic, Acclaim

Cory Dean, C.E.T.VP, Business Development

CanEra Inc., CanEra Energy Corp., CanEra Resources, Canetic, Acclaim, Landover, Northrock

Thomas J. Emerson, B.A.VP, Land

CanEra Inc., CanEra Energy Corp., CanEra Resources, Cyries, Burlington, Canadian Hunter

Sean Kinoshita, P.Eng.VP, Production

CanEra Inc., CanEra Energy Corp., CanEra Resources, Peyto, Husky, Renaissance

Frank Serpico, B.A.VP, Marketing

SanLing Energy, Spyglass Resources, Pace Oil & Gas, Provident Energy

David W. Sakal, B.Sc., P.EngVP, Operations

CanEra Inc., CanEra Energy Corp., CanEra Resources, Focus , Renaissance

Jeffrey R. Wallace, B.Sc., P.Geol.VP, Exploration

CanEra Inc., Legacy Oil + Gas, CanEra Resources, Canetic, Penn West, Trioil, Yangarra, Rider, Husky, Renaissance

Annie Belecki, B.A., LL.B.General Counsel

Lightstream, TCPL

Seasoned management team

Worked together in multiple successful corporate iterations

Strong buy-&-exploit value-creation record

Demonstrated ability to access quality deal flow and transact

Ability to opportunistically monetize

Patient & strong private equity support in current environment

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Private Equity Sponsors

Apollo Global ManagementNew York, N.Y.

A leading global alternative investment manager with over US$232 billion in investor commitments across its private equity, credit and real estate funds and other investment vehicles.

GSO Capital PartnersNew York, N.Y.

One of the largest credit-oriented alternative asset managers in the world with assets under management of US$139 billion.

525 – 8th Ave SW, Ste 2800Calgary, AB T2P 1G1 Canada(403) 268-7800www.ridgeback.com

Corporate Information

Independent Engineers Sproule & Associates, Ltd

Auditors Deloitte LLP

Legal Counsel Blakes, Cassels & Graydon LLP

Banking Syndicate Toronto Dominion Bank, Royal Bank of Canada, Bank of Montreal, Bank of Nova Scotia, Canadian Imperial Bank of Commerce, National Bank of Canada, Alberta Treasury Branches

, Executive Chairman & CEOT: (403) 218-8989E: pcharron@ridgeback.com

, PresidentT: (403) 218-8985E: dbroshko@ridgeback.com

APPENDIX

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Ridgeback Hedge Position(1)

1 Hedge position as at October 4, 20193 WTI hedges are transacted in both CAD and USD but are presented in US @ $0.7560

BOE

(bbl/d) ($/bbl) (bbl/d) Long Put Short Call (bbl/d) Short Put Long Put Short Call (bbl/d) ($/bbl) (bbl/d) ($/bbl) (boe/d)

3Q19 0 0.00 4,000 45.24 70.12 3,500 44.29 50.08 60.84 7,500 47.50 4,000 10.19 7,500

4Q19 0 0.00 5,000 46.79 67.61 2,750 44.66 50.10 61.35 7,750 47.97 4,000 10.19 7,750

1Q20 2,500 54.44 5,500 55.13 61.93 0 0.00 0.00 0.00 8,000 54.92 500 10.45 8,000

2Q20 2,500 54.44 5,500 55.13 61.93 0 0.00 0.00 0.00 8,000 54.92 500 10.45 8,000

3Q20 1,000 53.59 1,000 53.08 58.46 0 0.00 0.00 0.00 2,000 53.34 500 10.45 2,000

4Q20 1,000 53.59 1,000 53.08 58.46 0 0.00 0.00 0.00 2,000 53.34 500 10.45 2,000

WTI Hedges (USD)3

MSW Diff. (USD)

Swaps 3-Way Total WTI Basis SwapsCollars

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Track Record of Value Creation – CanEra

Entity

Equity Commitment

(C$MM)

Acquisition Cost

(C$MM)

Equity Invested (C$MM)

Exit(C$MM)

Annualized Return on Equity (%) MOIC (x)

CanEra Resources Inc. (2008-10)Private Equity Sponsors: Riverstone Holdings & Natural Gas Partners

$350 $300 $204 $603 160% 2.3x

CanEra Energy Corp. (2010-14)Private Equity Sponsors: Riverstone Holdings & Natural Gas Partners

$390 $766 $425 $1,100 35% 1.8x

CanEra Inc. (2015-17)Private Equity Sponsors: Riverstone Holdings & Natural Gas Partners

• Committed $450MM of equity• ~$3B of potential transactions evaluated from Sept 2014 to Nov 2016• No transactions completed; wound up in Feb 2017