Centennial Resource Development : Q2 2020 Centennial Resource Development Earnings Conference Call Presentation

Core Oil

Delaware Basin Pure-Play

Second Quarter 2020 Earnings Presentation

August 3, 2020

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," "goal," "plan," "target" 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, the COVID-19 pandemic and governmental responses thereto, 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 non-GAAP financial measures, such as Adjusted EBITDAX, Net debt and Net debt to last twelve months ("LTM") EBITDAX. Please refer to slide 15 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 on slide 15 from net income (loss) 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.

The Company defines Net debt as the aggregate principal amount of the Company's notes outstanding minus cash and cash equivalents. The Company presents this metric to help evaluate its capital structure and financial leverage and believes that it is widely used by professional research analysts, including credit analysts, and others in the evaluation of total leverage.

The Company defines Net debt to LTM EBITDAX as Net debt (defined above) divided by Adjusted EBITDAX (reconciled on slide 15) for the prior twelve-month period. The Company presents this metric to show trends that investors may find useful in understanding the Company's ability to service its debt. This metric is widely used by professional research analysts, including credit analysts, in the valuation and comparison of companies in the oil and gas exploration and production industry.

2

Centennial Resource Development Overview

Key Company Statistics

Operational Overview

Production

Q2 Total Production (Boe/d)	68,245
Q2 Oil Production (Bo/d)	37,411
% oil	55%
Capital Expenditures ($ mm)
Q2 Total Capital Exp.	$28.0
Updated FY 2020 Total Capital Exp. $240 - 270
1H'20 Capital Exp.	$203
Implied 2H'20 Capital Exp.1	~$52
Acreage (as of 12/31/19) 2
Total net acreage	~78,200
% CDEV Operated	93%
% Held by Production	87%
Financial Overview (Q2 2020)
Leverage
First Lien Debt / LTM EBITDAX	0.9x
Net Debt / LTM EBITDAX	2.6x
Net Debt / Book Capitalization	29%

Q2 2020 Highlights

• Reduced capital expenditures by 84% compared to Q1 2020
• Reduced year-to-date average well costs by over 20% compared to FY 2019
• Reduced LOE per unit costs for the third consecutive quarter
• Executed debt exchange offer, reducing total senior note debt by $127 million
• Added fourth quarter 2020 oil hedges at ~$39 per barrel to protect against downside risk
• Minimal federal acreage exposure (~5% of total net acreage)

Asset Overview2
Southern Delaware (TX)	Northern Delaware (NM)
Ward
NM	NM
TX	TX

Reeves

Lea

	Pecos
TX: ~59,350			NM: ~18,850
net acres1			net acres1

(1) 2H'20 implied total capital expenditure figure equal to midpoint of revised 2020 guidance range less actual capital incurred in 1H'20

(2) As of 12/31/19; does not include mineral or surface acreage positions

3

Centennial's Response to Macro Environment

Operational Initiatives

• Reduced operated rig count from five to zero in April 2020 and halted completion activity
• Total capital budget reduced by ~60% from original guidance
• Curtailed ~20% of production during May in response to weak realized prices (majority of wells back online by end of June)

Cost Control & Margin Improvement

• Realized significant reductions to D&C costs, lease operating expenses and G&A
• • Reduced D&C costs per well by over 20%, compared to FY 2019
  • Reduced LOE and G&A1 unit costs by 17% and 12%, respectively from Q1 2020 to Q2 2020

Financial Action

1. • Executed debt exchange resulting in reduction to senior unsecured notes and lower interest expense
   • Amended credit facility to replace total leverage covenant through YE'21 with first lien leverage covenant of 2.75x
   • Hedged significant amount of 2020 oil volume to mitigate downside risk
2. Q2'20 Cash G&A excludes one-time severance payments related to "Reduction In Force" (RIF) of ~$2.9mm incurred in Q2 2020

4

Focused on Operating Cost Control and Margin Expansion

Operational Cost Improvement

§	Improving operational
	efficiency
§	Lowering water
	disposal, electricity,
	chemicals and rental
	equipment costs
§	Optimizing lift method

Historical Cash Unit Costs ($/Boe)
				LOE
$10.81				GP&T
$10.24			Cash G&A
$1.81		$9.57
	$2.12	$8.69

$1.99

§ Reduced non-essential

$2.97

$1.75 1

	spend on workover
	related activity
§	Reduced workforce to
	better align with
	anticipated activity
	levels
§	Reduced compensation
	for all employees and
	directors
§ Reduced non-payroll
	expenses, such as IT,
	office, professional
	fees, etc.

$2.82

$2.59

$2.78

$6.03

$5.30$4.99

$4.16

Q3'19	Q4'19	Q1'20	Q2'20

(1) Represents implied cash G&A excluding one-time severance payments related to "Reduction In Force" (RIF) of ~$2.9mm incurred in Q2 2020

5

Review of Key LOE Initiatives

1§ Electricity: Transitioning more	1	In-Field Generator Usage (#)
facilities to electric power,		~135
resulting in lower equipment
rental costs

• Phase 1 of Centennial's electric substation complete

⎯ ~85 of 135 generators			~50
have been removed with						~15
phase 1 of the substation
⎯ Phase 2 will most likely be
	YE 2019	Q2 2020	YE 2020E
completed end of Q3 or
early Q4	Artificial Lift Optimization
3
2§ Water Disposal: Continuing	AL Failure Rate (Failures / Well / Year)
to optimize CDEV operated
water disposal system

	0.58
⎯	Trucked water disposal
	down to ~3% from ~11% in
	FY 2019	0.38
3§ Artificial Lift: Ongoing
transition from ESPs to gas lift
⎯ Lower failure rate, resulting
	in less workover expense
	and downtime
	FY 2019	YTD 2020

2 Trucked Produced Water (% of total)

~11%
	~3%
FY 2019	YTD 2020

Historical Artificial Lift Method Allocation

ESP Gas Lift Flowing Rod / Misc

~20%~40%

Q2'19Q2'20

6

DC&F Cost Evolution

Review of DC&F Cost Initiatives

• Significant reduction in cycle times
• • 25% decrease in spud to rig release days from 2019
  • 34% increase in completion stages per day from 2019
• D&C design / process refinement
• • Implementing new casing design in Reeves County
  • Expanding water recycling program across position
• Proactive response to current commodity price environment
• • Active negotiations with service providers
  • Thorough evaluation of all on-site personnel and equipment
• Majority of D&C cost and efficiency improvements are not subject to future inflationary pressure

DC&F Cost / Lateral Foot - Extended Lateral Average (1.5 & 2 Section)1

$1,600

$1,400 ~$1,350

$1,200

$1,000	~$950/ft
$800	~$850/ft

$600

$400

$200

$0
H1 2019	H2 2019		H1 2020	Go-Forward Estimate
Spud to Rig Release (Days)				Completion Stages / Day
31.8						8.2
24.5						6.1
			18.3			4.8

2018

2019

2020

2018

2019

2020

(1) Represents total completed well costs - including drilling, completion, facilities and flowback costs

7

Debt Exchange Overview

Debt Exchange Overview ($ mm)1

• Closed debt exchange transaction in May 2020
• ~$254mm of senior unsecured notes tendered, resulting in issuance of ~$127mm Second Lien senior secured notes
• Reduced principal amount of senior unsecured debt outstanding by ~$127mm
• Anticipate ~$6mm in annualized interest expense savings
• Net impact of ~$8mm of total incremental debt during Q2'20

		Q1 2020	Q2 2020	Change
8.000%	Second Lien Notes due 2025	$0.0	$127.1	$127.1
5.375%	Sr. Unsec. Notes Due 2026	$400.0	$289.4	($110.6)

Debt Exchange Transaction Impacts

Annualized Interest Expense ($ mm)

		Sr. Unsec. Note due 2027		Sr. Unsec. Note due 2026
		Sr. Sec. Note due 2025
$56		$50
			$22				$10
							$16
$34
	$24
		Pre-Debt Exchange	Post-Debt Exchange

Senior Note Principal Outstanding ($ mm)1

$900

$773

$400$127

6.875% Sr. Unsec. Notes Due 2027	$500.0	$356.4	($143.6)
Total Sr. Notes Outstanding	$900.0	$772.9	($127.1)

$500

$289

$356

Pre-Debt Exchange

Post-Debt Exchange

1. Reflects the aggregate principal amount of notes outstanding

8

Capital Structure and Liquidity Overview

Capital Structure Overview

• First Lien debt / LTM EBITDAX of 0.9x and Net debt / LTM EBITDAX of 2.6x
• ~$300mm of liquidity as of 6/30/20 (based on $700mm borrowing base and $668 facility availability)2
• Amended credit facility to replace total leverage covenant through YE 2021 with first lien leverage covenant of 2.75x LTM EBITDAX, stepping down to 2.5x during 2022
• No note maturities until 2025

Debt Maturity Schedule ($ mm)

Credit Facility Borrowings

8.000%	Senior Secured Notes	No note maturities until 2025
5.375%	Senior Unsecured Notes
6.875%	Senior Unsecured Notes

Pre-Debt Exchange Principal

			$370				$356
						$289
					$127
2020	2021	2022	2023	2024	2025	2026	2027

Capitalization and Liquidity at 6/30/20 ($ mm)

	As of
Capitalization	6/30/20
Cash and cash equivalents	$7.2
Revolving credit facility	$370.0
8.000% First Lien Notes due 20251	$127.1
5.375% Sr. Unsecured Notes due 20261	$289.4
6.875% Sr. Unsecured Notes due 20271	$356.4
Total debt	$1,142.9
Book equity	$2,734.5
Total capitalization	$3,877.4
Credit statistics
First Lien debt / LTM EBITDAX	0.9x
Net debt / LTM EBITDAX	2.6x
Net debt / book capitalization	29%
Liquidity ($ mm)
Borrowing base	$700.0
Facility availability2	668.2
Less: Revolver borrowings	(370.0)
Less: Letters of credit	(8.2)
Plus: Cash	7.2
Liquidity	$297.2
Facility availability utilization	56%

Note: Amounts may not sum due to rounding
(1)	Reflects the aggregate principal amount of notes outstanding	9
(2)	Borrowing base subject to an availability blocker $31.8 million as a result of the debt exchange transaction

2H'2020 Capital to be Funded With Cash Flow

FY 2020 Total Capital Expenditures ($mm)1

$255
	80% of estimated FY 2020
2H'20
Capital:	total capital spent in 1H'2020
$52	$203
	$175

1H'20

Capital:

$203

$28

Anticipated 2H 2020 capital spend expected to be funded through operating cash flow2

20% of estimated FY 2020 total capital spent in 2H

$52 total

in 2H

		FY 2020 Annual	Q1 2020	Q2 2020	Q3 2020	Q4 2020
		Guidance Mid-Point	Actual	Actual	Implied3	Implied 3
(1)	Total capital expenditure figures represent midpoint of initial and revised 2020 guidance ranges
(2)	Assuming current strip pricing				10
(3)	2H'20 implied total capital expenditure figure equal to midpoint of revised 2020 guidance range less actual capital incurred in 1H'20; quarterly breakdown is illustrative and not indicative of specific

Q3 / Q4 relative spending

Quarterly Financial Results

Financial Summary ($mm, unless otherwise noted)1

				FY 2019				FY 2020
($ in millions, unless specified)		Q1	Q2	Q3	Q4		Q1	Q2
Average Daily Production (Boe/d)	72,035	76,122	76,312	79,734	71,820	68,245
Average Daily Oil Production (Bo/d)	40,508	43,105	42,079	45,031	41,512	37,411
% Oil	56%	57%	55%	56%	58%	55%
Financial highlights
Total Revenue	$214.6	$244.2	$229.1	$256.4	$192.8	$90.5
Pre-Hedge Realized Oil Price ($/Bbl)	$48.15	$54.63	$51.71	$53.25	$45.14	$21.47
Adjusted EBITDAX2	$141.1	$170.1	$132.9	$160.1	$113.5	$24.4
Net Income (loss)3	($8.1)	$17.9	($3.6)	$9.6	($548.0)	$5.3
Unit Costs ($/Boe)
Lease Operating Expense		$4.61	$5.04	$6.03	$5.30	$4.99	$4.16
Gathering, Processing & Transportation		2.32	2.34	2.97	2.82	2.59	2.78
Severance & Ad Valorem Taxes		2.49	2.48	1.74	2.41	2.54	0.92
Cash G&A		1.89	1.78	1.81	2.12	1.99	2.21
Depreciation, Depletion & Amortization	14.89	16.18	16.06	16.75	15.49	14.98
Capital Expenditures Incurred
Drilling & Completion	$188.4	$179.8	$160.5	$162.8	$146.8	$21.4
Facilities, Infrastructure and Other	45.6	44.6	40.6	31.2	25.2	6.5
Land	11.2	13.0	11.0	3.2	3.4	0.1
Total Capital Expenditures	$245.2	$237.4	$212.1	$197.2	$175.4	$28.0
Cash and Cash Equivalents		$89.5	$28.4	$10.9	$10.2	$3.8	$7.2
Total Debt Outstanding4		$900.0	$900.0	$1,020.0	$1,075.0	$1,135.0	$1,142.9
Liquidity5	$888.7	$827.6	$690.1	$634.5	$468.1	$297.2

1. Amounts may not sum due to rounding
2. Adjusted EBITDAX is not presented in accordance with generally accepted accounting principles in the United States. Please refer to slide 13 for a reconciliation of Adjusted EBITDAX to net income

	(loss), the most comparable GAAP measure	11
(3)	Net income (loss) attributable to common shareholders
(4)	Reflects the aggregate principal amount
(5)	Liquidity defined as cash, plus availability under the revolving credit facility elected commitment amount in prior periods (FY'19) and borrowing base in current period (FY'20)

FY 2020 Guidance Summary

Guidance Summary

• Updated production guidance ranges reflect revised development plans
• • No drilling rigs currently active
  • Expect to complete 5 DUCs in New Mexico during Q3 2020 and add 1 drilling rig in Q4 2020
• Total capital guidance represents a 60% reduction from original 2020 guidance1
• Revised guidance reflects D&C and operational cost reductions driven by efficiencies in the field
• Unit costs lowered for all line items relative to initial 2020 guidance
• • LOE lowered at the midpoint by ~23%
  • G&A and GP&T lowered by ~5% and ~8%, respectively
• Average completed lateral length for 2020 expected to be ~7,500'
• Average working interest for operated completions of ~90%

FY 2020 Guidance Summary

FY 2020 Guidance

Production

	Net Average Daily Production (Boe/d)	64,000	-	68,000
	Net Average Daily Oil Production (Bo/d)	34,500	-	36,500
	Production Costs ($ / Boe)
	Lease Operating Expense	$4.60	-	$5.00
	Gathering, Processing & Transportation	$2.80	-	$3.10
	Depreciation, Depletion, Amortization	$14.50	-	$16.50
	Cash General and Administrative	$1.95	-	$2.15
	Stock-based Compensation	$0.80	-	$1.00
	Severance and Ad Valorem Taxes (% of revenue)	7.0%	-	9.0%
	Capital Expenditure Program ($MM)
	Drilling & Completions	$200	-	$220
	Facilities, Infrastructure and Land	40	-	50
	Total Capital Expenditures	$240	-	$270
	Operated Drilling Program
	Wells Spud (Gross)	17	-	23
	Wells Completed (Gross)	30	-	33

(1) Percentage reduction calculated relative to midpoint of original FY 2020 total capital incurred guidance

12

Hedge Position Overview

Hedge Strategy Summary

§ Hedge strategy represents a shift

in corporate philosophy

Hedge Position Overview as of July 31, 2020

		FY 2020				FY 2021
	Q3	Q4	Bal. 2020		Q1	2021

WTI Fixed Price Swaps

§ Manage potential downside risk to

commodity prices while preserving

upside optionality

⎯ Systematically add hedges on

a rolling forward basis

⎯ Shifting focus to FY 2021

§ Align hedges with firm sales &

regional price index exposure

§ Maintain a simple hedge portfolio

comprised primarily of fixed price

swaps & two-way collars

§ Utilize hedges to protect liquidity

Total Volume (Bbl)	2,300,000	1,196,000	3,496,000
Daily Volume (Bbl/d)	25,000	13,000	19,000
Weighted Average Price ($ / Bbl)	$26.83	$38.89	$30.95
Brent Fixed Price Swaps
Total Volume (Bbl)	--	--	--
Daily Volume (Bbl/d)	--	--	--
Weighted Average Price ($ / Bbl)	--	--	--
WTI Collars
Total Volume (Bbl)	--	184,000	184,000
Daily Volume (Bbl/d)	--	2,000	1,000
Weighted Average Floor ($ / Bbl)	--	$39.00	$39.00
Weighted Average Ceiling ($ / Bbl)	--	$44.50	$44.50
Mid-Cush Basis Swaps
Total Volume (Bbl)	1,472,000	1,196,000	2,668,000
Daily Volume (Bbl/d)	16,000	13,000	14,500
Weighted Average Price ($ / Bbl)	$0.52	$0.51	$0.52
Henry Hub Fixed Price Swaps
Total Volume (MMBtu)	2,760,000	2,150,000	4,910,000
Total Volume (MMBtu/d)	30,000	23,370	26,685
Weighted Average Price ($/MMBtu)	$2.03	$2.40	$2.19
Waha Differential Basis Swaps
Total Volume (MMBtu)	2,760,000	930,000	3,690,000
Daily Volume (MMBtu/d)	30,000	10,109	20,054
Weighted Average Price ($/MMBtu)	($1.62)	($1.62)	($1.62)

--	--
--	--
--	--
90,000	90,000
1,000	247
$45.56	$45.56
--	--
--	--
--	--
--	--
--	--
--	--
--	--
1,800,000	1,800,000
20,000	4,932
$2.68	$2.68
--	--
--	--
--	--

Note: Hedge positions as of July 31, 2020

13

Key Centennial Objectives

Operational and Financial Mindset: Focusing on what we can control

• Improve cash margin through LOE optimization and corporate cost control
• Continue to drive structural improvements to D&C costs and efficiencies
• Proactive management of balance sheet and liquidity
• Implementing a fulsome hedge strategy to mitigate future price volatility

Return to efficient development of high-quality asset base, with

improved well economics and cash margins

14

Reconciliation of Adjusted EBITDAX to Net Income (Loss)

Adjusted EBITDAX reconciliation ($ thousands)1

					FY 2019			FY 2020
	($ in thousands, unless specified)		Q1	Q2	Q3	Q4		Q1	Q2
	Net income (loss) attributable to common shareholders	($8,112)	$17,877	($3,585)	$9,618	($547,983)	$5,330
	Net income (loss) attributable to noncontrolling interest		(425)	1,125	(128)	44	(2,362)	0
	Interest expense	10,160	14,437	15,246	16,148	16,421	17,371
	Income tax expense (benefit)	(2,263)	5,928	1,393	739	(83,208)	(1,916)
	Depreciation, depletion and amortization	96,558	112,114	112,720	122,851	101,258	93,020
	Impairment and abandonment expenses	31,264	4,418	6,745	4,818	611,300	19,425
	Gain on exchange of debt	0	0	0	0	0	(143,443)
	Non-cash portion of derivative loss (gain)	5,494	4,260	(9,740)	(4,108)	8,452	22,963
	Stock-based compensation expense	5,884	6,076	7,357	6,998	5,892	4,270
	Exploration expense	2,516	3,861	2,869	2,144	4,009	4,051
	Workforce reduction severance payments	0	0	0	0	0	2,884
	Transaction costs	0	0	0	0	0	476
	(Gain) loss on sale of long-lived assets	2	(9)	22	842	(245)	2
	Adjusted EBITDAX	$141,078	$170,087	$132,899	$160,094	$113,534	$24,433

(1) Adjusted EBITDAX is a non-GAAP financial measure

15