Core Oil Delaware Basin Pure-Play Third Quarter 2018 Earnings Presentation November 5, 2018
Important Information Forward-Looking Statements The information in this presentation includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical fact included in this presentation, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this presentation, the words could, believe, anticipate, intend, estimate, expect, project and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management s current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the development, production, gathering and sale of oil and natural gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures and the other risks described in our filings with the Securities and Exchange Commission. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this presentation. Use of Non-GAAP Financial Measures This presentation includes the non-gaap financial measure, Adjusted EBITDAX. Please refer to slide 16 for a reconciliation of Adjusted EBITDAX to net income, the most comparable GAAP measure. We believe Adjusted EBITDAX is useful as it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period and against our peers without regard to financing methods or capital structure. We exclude the items listed in slide 16 from net income in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company s financial performance, such as a company s cost of capital and tax structure, as well as the historic cost of depreciable assets, none of which are components of Adjusted EBITDAX. Our presentation of Adjusted EBITDAX should not be construed as an inference that our results will be unaffected by unusual or non-recurring items. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies. 2
Centennial Resource Development Overview Q3 2018 Financial and Operational Highlights Asset Map Delivering production growth Increased daily crude oil production 15% quarter-over-quarter and 71% year-over-year Increased daily equivalent production 9% quarter-over-quarter and 81% year-over-year Maintaining technical excellence Announced strong well results from six intervals in the Northern and Southern Delaware Basins, including one of the best First Bone Spring wells drilled in New Mexico Adding inventory through disciplined bolt-on acquisitions Acquired approximately 2,900 net acres adjacent to existing positions in Reeves County, Texas and Lea County, New Mexico Continuing to demonstrate cost-control YTD unit costs at lower half of guidance ranges Advantaged midstream infrastructure and flow assurance Northern Delaware Net acres: ~16,400 1 2018 drilling plan: 1 rig Loving Winkler Southern Delaware Net acres: ~63,700 1 2018 drilling plan: 6 rigs One of the few mid-cap E&Ps to secure takeaway out of the Permian Basin for the majority of its crude oil and essentially all of its residue natural gas Ward Maintaining conservative balance sheet and strong liquidity Net Debt / Book Capitalization of 13%; Net Debt / Q3 annualized EBITDAX of 0.7x Liquidity as of 9/30/18 of $718mm (pro forma for fall redetermination) 2 Reeves Pecos Note: Acreage map highlights current acreage position (shown pro forma for YTD A&D activity) (1) Net acreage as of 12/31/17; pro forma for 4,000 net acre Northern Delaware acquisition and ~8,600 net acre Southern Delaware divestiture; figures do not include Q3/Q4 A&D activity (2) Liquidity as of 9/30/18, pro forma for elected commitment increase to $800mm; net of $0.9mm in letters of credit 3
Centennial Game Plan Stay focused as pure-play Delaware Basin company Maintain high, unhedged oil growth through 2020 Post 2020 become FCF positive, establish dividend and continue strong (but not inordinate) oil growth rate Not inclined to grow through corporate or large scale M&A Will continue to grow through tactical, bolt-on acquisitions while expanding inventory on existing acreage Max net debt / capital ratio of ~25% (actual 13% at 9/30/18) Target 2020 GAAP ROE / ROCEs of 14 17%, assuming $75 WTI 4
Recent Bolt-On Acquisitions Update Acquisition Overview Well Locator Map Recently closed bolt-on acquisitions in the Northern and Southern Delaware totaling ~2,900 net acres Northern Delaware Acquisitions Acquired 820 net acres for ~$26mm Implies an adjusted purchase price of ~$26,000 / net acre 1 Increases working interest and provides opportunity for future extended lateral development N. Delaware acquisitions S. Delaware acquisition Southern Delaware Acquisition Acquired 2,100 net acres Directly offsets two recent wells (Highlander and Doc Gardner) with an average IP-30 of ~2,335 Boe/d Cheddar IP-30: 1,713 Boe/d Bolt-on Acquisition Offset Well Results 2 Cum. oil production (Mbo) 80 60 40 20 Cheddar 3BS Fed Com #1H Q1'17 - Q2'18 Avg. 2.0 Section Lateral Cum. oil production (Mbo) 80 60 40 20 Highlander #U49H Doc Gardner A #U23H Q1'17 - Q2'18 Avg. 2.0 Section Lateral Loving Ward Highlander IP-30: 2,339 Boe/d Winkler Doc Gardner IP-30: 2,327 Boe/d 0 0 10 20 30 Days on production 0 0 10 20 30 Days on production Well Statistics Cheddar 3BS Federal Com #1H Target Formation 3rd BS Sand Lateral Length (ft.) 9,600 IP-30 (Boe/d) 1,713 % Oil 75% Well Statistics Highlander #U49H Doc Gardner A #U23H Target Formation Upper WC A Upper WC A Lateral Length (ft.) 7,300 12,200 IP-30 (Boe/d) 2,339 2,327 % Oil 79% 82% Reeves Pecos (1) Purchase price adjusted for value of associated PDP production (2) Cheddar 3BS Fed Com 01H shown on a non-normalized basis, Highlander #U49H and Doc Gardner A #U23H normalized to 9,500 lateral 5
Centennial Inventory / A&D Review Centennial Growth / A&D Strategy YTD 2018 Inventory Additions Add organic inventory through exploration of untested uphole zones Pursue tactical bolt-on acquisitions at reasonable valuations, supported by strong offset well results Avoid large corporate M&A transactions 200+ gross locations Organic Reeves Co. 3 rd Bone Spring Sand inventory additions Differentiated strategy should provide superior GAAP returns versus peers YTD 2018 exploration and A&D activity has replaced approximately 4x the anticipated completions in 2018 75 85 gross locations Gross Operated Wells Completed (FY 2018E) ~100 gross locations YTD 2018 Gross Operated Locations Added A&D / Leasing inventory additions 6
Q3 2018 Well Results Review Northern Delaware Highlights Pirate State #301H Tour Bus 23 State 2-Well Pad Well Locator Map Best 1 st Bone Spring well completed in NM First pad development opportunity in NM 50 Pirate State #301H Q1'17 - Q2'18 Avg. 1-Section Lateral 50 Tour Bus 23 State #505H Tour Bus 23 State #506H Q1'17 - Q2'18 Avg. 1-Section Lateral 40 40 Cum. oil production (Mbo) 30 20 Cum. oil production (Mbo) 30 20 10 10 Tour Bus 23 State Pad 0 0 10 20 30 0 0 10 20 30 Days on production Days on production Pirate State #301H Well Statistics Pirate State #301H Target Formation 1st BS Sand Lateral Length (ft.) 4,800 IP-30 (Bo/d) 1,520 % Oil 79% IP-30 / 1,000 (Bo/d) 317 Well Statistics Tour Bus #505H Tour Bus #506H Target Formation 2nd BS Sand 2nd BS Sand Lateral Length (ft.) 4,600 4,500 IP-30 (Bo/d) 927 1,060 % Oil 83% 85% IP-30 / 1,000 (Bo/d) 201 234 Note: Cumulative oil production curves shown on an non-normalized basis, Q1 2017 Q2 2018 average only includes production from 1.0, 1.5, or 2 section laterals depending on highlight well lateral length 7
Q3 2018 Well Results Review Southern Delaware Highlights Big House 3-Well Pad War Eagle A Unit #L49H Well Locator Map Co-development across 3 WC formations Big Chief area delineation well outperforming 60 50 Big House D (U WC A) Big House E (WC B) Big House F (L WC A) Q1'17 - Q2'18 Avg. 1.5-Section Lateral 60 50 War Eagle A Unit #L49H Q1'17 - Q2'18 Avg. 1.5-Section Lateral Cum. oil production (Mbo) 40 30 20 Cum. oil production (Mbo) 40 30 20 Big House Ward 3 Well Pad 10 10 Reeves 0 0 10 20 30 Days on production Well Statistics Big House Pad Average Target Formation U WC A, WC B, L WC A Lateral Length (ft.) 7,100 IP-30 (Bo/d) 1,195 % Oil 62% IP-30 / 1,000 (Bo/d) 169 0 0 10 20 30 Days on production Well Statistics War Eagle A Unit #L49H Target Formation Upper WC A Lateral Length (ft.) 7,400 IP-30 (Bo/d) 1,608 % Oil 87% IP-30 / 1,000 (Bo/d) 219 War Eagle A Unit #L49H Pecos Note: Cumulative oil production curves shown on an non-normalized basis, Q1 2017 Q2 2018 average only includes production from 1.0, 1.5, or 2 section laterals depending on highlight well lateral length 8
Delaware Basin Well Productivity (Texas only) Average Oil Well Performance Since 2017 (9-Month Cumulative Oil Production; Bo / ft.) 30 Large-caps 25 26 Cumulative Oil / Foot 20 15 10 Median: 18 Bo / Ft. 5 0 CDEV Source for all data: IHS Peer group includes: APA, APC, BHP, CRZO, CVX, CXO, EGN, EOG, FANG, JAG, MTDR, NBL, OAS, OXY, PDCE, PE, RDSA, REN, RSPP, WPX and XEC Note: Includes Culberson, Loving, Pecos, Reeves, Ward and Winkler Counties; excludes public operators with 4 or less wells; excludes wells with laterals under 3,000 ft. 9
Flow Assurance Summary Crude and Natural Gas Firm Transportation & Firm Sales Overview August 2018: Executed crude oil firm sales agreement with BP 20,000 Bo/d beginning in January 2019, increasing to 30,000 Bo/d in 2020 through 2024 Based off Midland pricing for 2019 and Brent-based pricing for 2020+ September 2018: Executed crude oil firm sales agreement with ExxonMobil Natural Gas Crude Oil 20,000 Bo/d in Q1 19 and increasing on a quarterly basis 40,000 Bo/d in Q1 20 and increasing gradually to 75,000 Bo/d in Q1 23 2019 pricing based off MEH Beginning in 2020, diversified pricing tied to three separate benchmarks In total, secured takeaway for >50,000 Bo/d in 2019 through firm sales agreements Represents ~70% of FY 2019 consensus oil estimate (adjusted for gross volumes) Existing agreements in-place with other major purchasers for remainder of 2019 oil volumes ~100% of expected residue gas under firm transportation or firm sales agreements to Waha and out of the Basin through 2022 Do not expect to flare any material amounts of gas for the foreseeable future Majority of natural gas gathered and processed by EagleClaw Note: All volume amounts represent gross volumes 10
Unit Cost Benchmarking: YTD Q3 2018 1 $11.94 $12.20 $12.63 $11.10 $11.23 $9.68 $9.99 3.18 2.75 3.38 4.18 3.64 $8.07 $8.40 $8.50 2.84 3.01 3.05 2.69 2.05 2.71 2.06 2.41 3.01 3.31 0.91 1.99 2.67 3.23 3.39 4.11 3.72 3.78 3.61 3.59 5.21 6.42 6.15 5.01 5.68 Peer 1 CDEV Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 LOE ($/Boe) Cash G&A ($/Boe) Production Tax ($/Boe) Source: FactSet, Company filings Note: Peer group includes CPE, CXO, EGN, FANG, JAG, LPI, MTDR, PE and WPX; amounts may not sum due to rounding (1) CDEV, CXO, MTDR, PE and WPX as of 9/30/18; remaining companies as of 6/30/18 11
Q3 2018 Capital Structure and Liquidity Overview Capital structure overview Capitalization and Liquidity ($ mm) 1 Conservative leverage profile Net Debt / Total Book Capitalization of 13% Capitalization summary As of 9/30/2018 Net Debt / Q3 annualized EBITDAX of 0.7x Liquidity as of 9/30/18 of $718mm (pro forma for fall redetermination) vs. $612mm at 6/30/18 Credit Facility fall borrowing base increase from $800mm to $1.0bn, with corresponding elected commitments increase from $600mm to $800mm Debt maturity schedule ($ mm) 3 $1,000 Borrowing Base $800 Elected Commitments 5.375% Senior Unsecured Notes $400 Cash and cash equivalents $59 Revolving credit facility $140 5.375% Senior Notes Due 2026 400 Total debt outstanding $540 Total shareholders' equity 2 $3,205 Net Debt / Q3 annualized EBITDAX 0.7x Net Debt / LTM EBITDAX 0.8x Net Debt / Total Book Capitalization 13% Liquidity summary 9/30/18 (Pro Forma) Credit Facility Borrowings (as of 9/30/18) $140 2018 2019 2020 2021 2022 2023 2024 2025 2026 Cash and cash equivalents $59 Credit facility availability 3 659 Liquidity 4 $718 (1) Amounts may not sum due to rounding (2) Total shareholders equity includes non-controlling interest (3) Credit facility availability as of 9/30/18 pro forma for elected commitment increase to $800mm; net of $0.9mm in letters of credit (4) Liquidity defined as cash, plus availability under the revolving credit facility 12
Maintaining Low Leverage Profile Net Debt / Total Capitalization 1 Net Debt / LQA EBITDAX 1,2 47% 1.4x 1.3x 1.3x 1.1x 33% 28% 25% 24% 0.8x 0.8x 0.7x 18% 13% Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 CDEV Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 CDEV Source: Company filings and consensus estimates Note: Peer group includes: CPE, EGN, FANG, JAG, LPI, and PE; dotted line represents median and excludes CDEV (1) CDEV and PE as of 9/30/18; remaining companies as of 6/30/18; pro forma for capital markets and A&D activity (2) LQA represents last quarter annualized 13
Q3 2018 Financial Results Summary Financial summary ($mm, unless otherwise noted) ($ in millions, unless specified) Q3 2017 Q2 2018 Q3 2018 Oil Production (Bo/d) 21,108 31,271 36,027 Natural Gas Production (MMcf/d) 51,444 83,205 85,180 NGL (Bbl/d) 5,018 12,389 12,706 Average Daily Oil Production (Boe/d) 34,700 57,528 62,930 % Oil 61% 54% 57% Financial highlights Total Revenue $ 111.6 $ 217.8 $ 234.9 Adjusted EBITDAX 1 74.3 164.6 177.9 Net Income 2 14.4 63.5 39.3 Net Income / Share 2 $ 0.06 $ 0.24 $ 0.15 Unit Costs ($/Boe) Lease Operating Expense $ 3.56 $ 3.66 $ 4.09 Gathering, Processing & Transportation 3.11 2.92 2.78 Severance & Ad Valorem Taxes 2.02 2.71 2.49 Cash G&A 3 3.12 1.84 2.02 Depreciation, Depletion & Amortization 13.28 14.32 14.41 Capital Expenditures Incurred Drilling & Completion 4 $ 163.3 $ 162.7 $ 222.4 Facilities, Infrastructure and Other 2.3 34.3 43.5 Land 14.2 6.2 7.7 Total Capital Expenditures $ 179.8 $ 203.2 $ 273.6 Cash and Cash Equivalents 2.6 42.7 58.9 Total Debt Outstanding $165.0 $430.0 $540.0 Liquidity 5 $ 186.7 $ 611.8 $ 518.0 (1) Adjusted EBITDAX is not presented in accordance with generally accepted accounting principles in the United States. Please refer to slide 16 for a reconciliation of Adjusted EBITDAX to net (loss) income, the most comparable GAAP measure (2) Net income attributable to Class A Common Stock; net income per share shown on a fully-diluted basis (3) Exploration expense of ~$1.2 mm related to G&G personnel stock-based compensation, salaries and related expenses was reclassified from the three months ended June 30, 2017 to the three months ended March 31, 2017 in order to conform to the current presentation (4) Q3 2017 Drilling & Completion capital expenditures incurred include well-level facilities (5) Liquidity defined as cash, plus availability under the revolving credit facility; liquidity of $518mm in Q3 2018 shown prior to the increase in elected commitments, pro forma liquidity as of the date of the redetermination, after giving effect to the increase in elected commitments is $718mm, based on balance sheet position and letters of credit outstanding as of September 30, 2018. 14
Hedge Position Overview FY 2018 FY 2019 Q4 Bal 18 Q1 Q2 Q3 Q4 FY 2019 MidCush Basis Swaps Total Volume (Bbl) 828,000 828,000 540,000 91,000 1,380,000 920,000 2,931,000 Daily Volume (Bbl/d) 9,000 9,000 6,000 1,000 15,000 10,000 8,030 Weighted Average Price ($ / Bbl) ($2.38) ($2.38) ($5.34) ($10.00) ($9.03) ($4.24) ($6.88) Henry Hub Fixed Price Swaps Total Volume (MMBtu) - - 2,700,000 2,730,000 2,760,000 2,760,000 10,950,000 Total Volume (MMBtu/d) - - 30,000 30,000 30,000 30,000 30,000 Weighted Average Price ($/MMBtu) - - $2.78 $2.78 $2.78 $2.78 $2.78 Waha Fixed Price Swaps Total Volume (MMBtu) - - 1,350,000 1,365,000 1,380,000 1,380,000 5,475,000 Daily Volume (MMBtu/d) - - 15,000 15,000 15,000 15,000 15,000 Weighted Average Price ($/MMBtu) - - $1.61 $1.61 $1.61 $1.61 $1.61 Waha Differential Basis Swaps Total Volume (MMBtu) 460,000 460,000 3,150,000 3,185,000 3,220,000 3,220,000 12,775,000 Daily Volume (MMBtu/d) 5,000 5,000 35,000 35,000 35,000 35,000 35,000 Weighted Average Price ($/MMBtu) ($0.43) ($0.43) ($1.31) ($1.31) ($1.31) ($1.31) ($1.31) (1) Hedge positions as of September 30, 2018 15
Reconciliation of Adjusted EBITDAX to Net Income Adjusted EBITDAX reconciliation ($ thousands) 1 Adjusted EBITDAX reconciliation to net income: Q3 2017 Q2 2018 Q3 2018 3 months ended Sept 30, 2017 3 months ended June 30, 2018 3 months ended Sept 30, 2018 Net income attributable to Class A Common Stock $14,447 $63,541 $39,288 Net income attributable to noncontrolling interest 1,813 3,941 2,386 Interest expense 1,015 5,791 6,534 Income tax expense 8,233 19,940 11,652 Depreciation, depletion and amortization 42,387 74,946 83,423 Impairment and abandonment expenses - 1,784 8,612 Non-cash mark-to-market derivative (gain) loss 1,286 (11,534) 18,437 Stock-based compensation expense 3,360 4,166 4,888 Exploration expense 1,622 1,867 2,712 Transaction costs 42 - - (Gain) loss on sale of oil and natural gas properties 141 141 (52) Adjusted EBITDAX $74,346 $164,583 $177,880 (1) Adjusted EBITDAX is not presented in accordance with generally accepted accounting principles in the United States 16