Ridgeback Resources Corporate Presentation October 2019 Disclaimer - PowerPoint PPT Presentation

Ridgeback Resources Corporate Presentation October 2019

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 and reserves, business plans for drilling and exploration, the estimated amounts and timing of capital expenditures, the assumptions upon which estimates are based and related sensitivity analyses, and other expectations, beliefs, plans, objectives, assumptions or statements about future events or performance (often, but not always, using words or phrases such 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 of infrastructure processing capacity, well costs, payout and IRR estimates. Statements relating to "reserves" are deemed to be forward looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in 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 and associated cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating expenses, all of which may vary materially. Actual reserve values may be greater than or less than the estimates provided herein. Unless otherwise noted, reserves referenced 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 as estimates 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 on information available at the time the assumption was made. Ridgeback believes that the expectations reflected in these forward-looking statements are reasonable but no assurance can 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 from those anticipated, expressed or implied by such statements. Risk factors include: financial risk of marketing reserves at an acceptable price given market conditions; volatility in market prices for oil and natural gas; delays in business operations; pipeline restrictions; infrastructure construction schedule delays and cost overruns; blowouts; the risk of carrying out operations with minimal environmental impact; industry conditions including changes in laws and regulations including the adoption of new environmental laws and regulations and 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 a reasonable cost; increased competition for, among other things, capital, acquisitions of reserves and undeveloped lands; competition for and availability of qualified personnel or management; incorrect assessments of the value of acquisitions and exploration and development programs; unexpected geological, technical, drilling, construction and processing problems; availability of insurance; fluctuations in foreign exchange and interest rates; general economic, market and business conditions; uncertainties associated with regulatory approvals; uncertainty of government policy changes; uncertainties associated with credit facilities and counterparty credit risk; and changes in income tax laws, tax laws, crown royalty 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 those anticipated, 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 certainty as these are interdependent. Ridgeback assumes no obligation to update forward-looking statements should circumstances or management's estimates or opinions change. Certain information contained herein have been prepared by third-party sources. The information provided herein has not been independently audited or verified by the Company. 2

Corporate Snapshot Operating & Financial 2017 (1) 2018 2019e Production (boe/d) 21,000 22,808 23,000 Oil & NGL Weighting (%) 71% 75% 74% Deer Mountain Exit December (boe/d) 21,050 25,725 25,700 Swan Hills Kaybob Montney Net Debt Year-End ($MM) $267 $251 $181 (2) West Pembina Year End Debt to Adjusted Funds Flow 1.9x 1.2x 0.8x Cardium SE Sask Bakken & Operating Netback ($/boe) $24.12 $30.61 $29.65 Mississippian Adjusted Funds Flow from Operations ($MM) $142 $211 $218 (2) AB SK Light oil weighted asset base Capital Expenditure ($MM) (4) $111 $175 $148 Free Cash Flow ($MM) $31 $36 $70  Large oil-in-place assets with exploitation and 1P Reserves (3) (MMBoe) optimization opportunities 75 80  ~88% operated + ~70% WI in focused 2P Reserves (3) (MMBoe) 114 118 core areas Average Corporate Decline Rate ~27%  Repeatable, low-risk growth complemented by 1 2017 operations reflect only 6 months of new management and strategic direction higher-impact drilling opportunities 2 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/X 3 Sproule year-end 4 Includes ARO spending 3

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 4

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 5

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 6

1H19 2019 Operating Results Six Months ended June 30 2019 2018 Production Crude 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 7

1H 2019 Financial Results Six Months ended June 30 2019 2018 ($MM) ($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 8