Centennial Resource Development : Q4 2020 Centennial Resource Development Earnings Conference Call Presentation

Core Oil Delaware Basin Pure-Play

Fourth Quarter & Full-Year 2020

Earnings Presentation

February 23, 2021

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 and weather risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating oil and gas 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, free cash flow (deficit), net debt and net debt to last twelve months ("LTM") EBITDAX. Please refer to slide 21 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 21 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.

Please refer to slide 22 for a reconciliation of free cash flow (deficit) to net cash provided by operating activities, the most comparable GAAP measure. We believe free cash flow (deficit) is a useful indicator of the Company's ability to internally fund its exploration and development activities and to service or incur additional debt, without regard to the timing of settlement of either operating assets and liabilities or accounts payable related to capital expenditures. The Company believes that this measure, as so adjusted, presents a meaningful indicator of the Company's actual sources and uses of capital associated with its operations conducted during the applicable period. Our computations of free cash flow (deficit) may not be comparable to other similarly titled measures of other companies. Free cash flow (deficit) should not be considered as an alternative to, or more meaningful than, cash provided by operating activities as determined in accordance with GAAP or as indicator of our operating performance or liquidity.

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 21) 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.

Centennial Resource Development Overview

Core Acreage and Strong Execution Track-Record

(1)Assuming a two-rig flat program and $45/Bbl oil pricing

• ⎯ Acreage in core of the Northern & Southern Delaware

• ⎯ ~81,700 net acres

• ⎯ Minimal Federal exposure (~4%)

• ⎯ ~97% operated and ~88% held by production

• ⎯ Realized significant improvements to cost structure and capital efficiency over the course of FY 2020

• ⎯ 2021 drilling program set to increase capital efficiency and carry operational improvements forward

• ⎯ Proven development from 10 distinct zones across the Northern and Southern Delaware

• ⎯ 15+ years of economic inventory1

• ⎯ No senior note maturities until 2025

• ⎯ ~$340mm of liquidity as of 12/31/20

• ⎯ Projected free cash flow generation supports organic de-leveraging and liquidity profile

• ⎯ Minimizing emissions through increased gas capture

• ⎯ Improvements in sustainability through water recycling program, minimizing water trucking and utilization of dual-fuel operations

Q4 Highlights and 2021 Overview

Q4'20 Financial and Operational Highlights

• ▪ Generated free cash flow and reduced total debt for the second consecutive quarter

• ▪ Added second operated drilling rig in late Q4 2020

• ▪ Achieved record spud-to-total depth for a two-mile lateral

• ▪ Reported 2020 annual production volumes, capital expenditures and total unit costs within full year guidance ranges

• ▪ Increased year-end acreage position primarily through cost-free swaps and trades

2021 Financial and Operational Plan

Key 2021 Objectives

• ▪ Generate free cash flow and further improve liquidity

• ▪ Execute on maintenance capital program

• ▪ Achieve significant organic deleveraging

• ▪ Increase capital efficiency and returns

• ▪ Maintain focus on ESG and sustainability initiatives

Overview of Plan

• ▪ Expect to generate $55 - 75mm of free cash flow in 2021 at current strip

  ⎯ Free cash flow positive down to a mid-$40's WTI price

• ▪ Plan to operate two-rig drilling program

• ▪ Expect to average full year oil production consistent with fourth quarter 2020 levels

• ▪ Operational plan supported by structurally lower well costs and increased lateral lengths

• ▪ Targeting < 2.5x leverage by year-end with a long-term target of < 1.5x

Maintaining Strong Execution - 2020 Actuals vs. Guidance

• ▪ FY 2020 production slightly above updated mid-point of guidance on both oil and oil equivalents

• ▪ Total unit costs at or below the midpoint of updated guidance ranges:

  ⎯ LOE represents a ~28% improvement compared toinitial guidance1

  ⎯

  Overall cash costs for FY 2020 represented a ~19% improvement compared to initial guidance1,2

• ▪ Total capital costs in-line with the mid-point of updated guidance, despite higher than anticipated activity levels in

  Q4'20

  ⎯ Spud three more wells than the guidance midpoint, completed wells in-line with expectations

Cash Costs2 vs Guidance Evolution ($ / Boe)

FY 2020 Actuals vs Guidance

Lease Operating Expense

Gathering, Processing & Transportation

Depreciation, Depletion, Amortization

Cash General and Administrative

Stock-based Compensation3

Severance and Ad Valorem Taxes (% of revenue)Capital Expenditure Program ($MM)

$4.25 $2.90 $14.50 $1.95 $0.80

6%

• - $4.50

• - $3.00

• - $15.50

• - $2.10

• - $0.90

• - 8%

$4.45 $2.90 $14.59 $2.03 $0.94 6.8%

P

$200 $40 $240

Drilling & Completions

Facilities, Infrastructure and Other

• - $220

• - $45

$212 $43

Wells Spud (Gross)

Wells Completed (Gross)

21 31

• - 24

• - 33

26 31

• (1) Initial guidance refers to FY'20 guidance released in February 2020 with Q4'19 Earnings

• (2) Cash costs defined as the sum of Lease Operating expense (LOE); Gathering, Processing & Transportation (GP&T); and Cash General & Administrative (G&A) expenses. Amounts may not sum due to rounding

• (3) Stock-based compensation for geographical and geophysical personnel is included with the Exploration and other expenses line item

Key Environmental Initiatives

Flared 0.5% of natural gas volumes in Q4'20

• ▪ Significant reduction in flared gas volumes

• ▪ Set a 2021 target of 1% flared gas

• ▪ Recycled and reused 4.8 MM Bbls of water in FY'20

  ~60% increase in recycled water volumes in FY'20

• ▪ Reduces produced water disposal volumes and freshwater consumption

• ▪ Continue to increase recycled water use across position

<1% of produced water volumes transported via truck in FY'20

• ▪ Continued optimization of operated water disposal system lowers dependency on trucking

• ▪ Reduces trucking-related emissions, improves safety, minimizes the potential for spills and lessens the impacts on local roads

Utilizing dual-fuel capabilities

• ▪ All contracted drilling rigs and completions crew to have dual-fuel capabilities

• ▪ Produces less emissions and is more cost efficient due to diesel fuel displacement

2021 Development Plan Overview

Increasing Capital Efficiency

• ▪ Extending lateral length to drive capital efficient development

  Operational Focus Items

  • - Eliminating single section lateral development for 2021

  • - Lower DC&F costs / lateral foot & higher ultimate recoveries

• ▪ Re-setting of corporate decline

  • - More stable production & cash flow base

  • - Improves free cash flow outlook

  • - Requires less investment for growth

• ▪ Maintaining cycle time improvements & efficiencies

• ▪ Allocating more activity to New Mexico acreage

~8,800'

~7,500'

FY 2020 AverageFY 2021 Estimate

New Mexico

Texas

58%	30%
70%
42%

FY 2020 Actual

FY 2021 Estimate

~15 - 18

~18 - 22

Initial 2020 GuidanceFY 2021 Estimate

~45 - 50%

~30 - 35%

FY 2020 ActualFY 2021 Estimate

(1)Initial 2020 guidance refers to FY'20 guidance released in February 2020 with Q4'19 Earnings

Recent Projects Have Significantly Reduced LOE

Review of LOE Cost Initiatives

Historical LOE Expense ($mm)

• ▪ Completed final phase of Centennial's electric substation and associated feeder lines in Q4'20

⎯ Facilitates transition of well-sites to electric power, representing significant driver of recent LOE reductions

⎯ Lower equipment rental costs as a result of reduction in in-field generators leased

⎯ Transition to line power increases reliability and reduces production downtime

• ▪ Completion of substation project significantly reduces go-forward infrastructure spending needs

• ▪ Continue to optimize Centennial's operated water disposal system through electrification projects and lower dependency on trucked water volumes

$42

Q3'19

Q4'19

Q1'20

Q2'20

Q3'20

Q4'20

Well Cost Evolution

Lower Well Costs Driven by Higher Efficiencies & Structural Cost Reductions

Review of DC&F Cost Initiatives

• ▪ Higher drilling and completion

  efficiencies, resulting in significant cycle

  time reduction

• ▪ D&C design / process refinement

  ⎯ Implementing new casing design in

  Reeves County

  ⎯ Expanding water recycling program across position

• ▪ Targeting $750-$850 / ft. target in 2021

• ▪ Recently set a new internal spud to total depth record for a two-section lateral of <8 days

⎯ Resulted in record ~$650 / ft DC&F well cost

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

$1,400

$1,200

$1,000

$800

$600

$400

$200

H1 2019

H2 2019

H1 2020

Q3'20 Average

Estimate 2

FY'21

Q1'21 To Date

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

• (2) Originally published on November 2, 2020

Acreage Position Overview

Acreage Status Update (YE 2020)

• ▪ Current Delaware Basin leasehold1 of 81,657 net acres (71% TX / 29% NM)

• ▪ Increased total net acreage by ~3,500 net acres year-over-year with <$5mm capital spend

  -

  Primarily driven by cost-free swaps and trades

• ▪ Increased New Mexico position by 27% YOY to ~23,900 net acres

  -

  Additions comprised almost entirely of state and fee acreage

• ▪ Minimal federal acreage exposure (~4% of total net acreage)

-

Represents a slight percentage reduction from YE 2019

Acreage Position Evolution

81,657

78,195

YE 2019

YE 2020

YE 2019

97% 93%

YE 2020

(1)Current leasehold count does not include mineral acres (1,472 net mineral acres as of YE 2020)

88%

87%

YE 2019

YE 2020

YE 2019

YE 2020

YE 2020 Proved Reserves Summary

Reserve Statistics

NSAI Proved Reserves (MBoe)

Drill-bit F&D costs1

$13.17 $13.53

Proved Reserves (Mboe)

SEC WTI Oil Price ($ / Bo)

301,139

298,902

Proved developed

$15.09 $11.48

F&D costs2

Organic reserves replacement ratio3

~240% ~90%

Reserves growth

15% (1%)

D&C capex

$691mm $212mm

50% 50%

$52.19

$36.04

YE 2019

YE 2020

PDPPUD

OilGasNGL

Source: NSAI prepared reserve report as of 12/31/20

• (1) Calculation defined as total 2020 exploration and developments costs of $302.4mm divided by the sum of total 2020 reserve extensions, discoveries and revisions (technical and pricing) of 22.3 MMBoe.

• (2) Calculation defined as total 2020 exploration and developments costs of $302.4mm divided by the sum of total proved developed reserve extensions and discoveries, transfers from proved undeveloped reserves, and proved developed reserve revisions (technical and pricing), totaling 26.3 MMBoe.

• (3) Calculation defined as the sum of total 2020 reserve extensions, discoveries and revisions (technical and pricing) of 22.3 MMBoe, divided by total 2020 production of 24.6 MMBoe.

Capital Structure & Liquidity Overview

Capital Structure Overview at 12/31/20

• ▪ Free cash flow of ~$30mm utilized for $25mm in debt payments under revolver during Q4'20

• ▪ $330mm drawn on credit facility

• ▪ ~$340 million of liquidity

• ▪ Leverage statistics:

  • ⎯ Net Debt / LQA EBITDAX of 3.5x

  • ⎯ Net Debt / LTM EBITDAX of 4.1x

  • ⎯ 1st Lien Debt / LTM EBITDAX of 1.2x (2021 covenant of < 2.75x)

Liquidity Evolution ($ mm)

Cash

Q2'20 Actual

Q3'20 ActualQ4'20 Actual

Capitalization and Liquidity ($ mm)

CapitalizationActual 12/31/20

Cash and cash equivalents $5.8

Revolving credit facility $330.0

Senior Secured Notes1 $127.1

Senior Unsecured Notes1 $645.8

Total debt

$1,102.9

Book equity

$2,604.0

Total capitalization

$3,706.9

Credit statistics

First Lien debt / LTM EBITDAX 1.2x

Net debt / LTM EBITDAX 4.1x

Net debt / LQA EBITDAX 3.5x

Net debt / book capitalization 30%

Liquidity ($ mm)Borrowing base

Facility availability2

$700.0

668.2

Less: Revolver borrowings (330.0)

Less: Letters of credit (4.3)

Plus: Cash 5.8

Liquidity3

$339.7

Facility availability utilization 49%

Borrowing base utilization 47%

Note: Amounts may not sum due to rounding

• (1) Reflects the aggregate principal amount

• (2) Equal to total borrowing base adjusted for ~$32mm availability blocker

• (3) Total liquidity calculation based on facility availability amount, not total borrowing base

No Near-Term Debt Maturities

Debt Maturity Schedule ($ mm)

Credit Facility Borrowings

8.000% Second Lien Secured Notes5.375% Senior Unsecured Notes6.875% Senior Unsecured Notes

$700 $668

$330 2

Borrowing Base

Facility Avalability1

$356

2023

$127

$289

2021

2022

2024

2025

2026

2027

• (1) Facility availability represents borrowing base less ~$32mm availability blocker

• (2) Represents borrowings under revolving credit facility as of 12/31/20

FY 2021 Guidance Summary

Guidance Summary

• ▪ Currently plan to operate a 2-rig program in FY 2021

• ▪ Anticipate full-year average oil production in-line with Q4'20 levels

• ▪ Total capital guidance of ~$285mm

• ▪ Expect to generate $55 - 75mm of free cash flow in 2021, at current strip pricing

• ▪ Average completed lateral length for 2020 expected to be ~8,800'

• ▪ Average working interest for operated completions of ~85%

• ▪ FY 2020 projected oil realizations of 90 - 94% of WTI

• ▪ Initial guidance ranges reflect preliminary assessment of recent winter storm impact on operations

FY 2021 Guidance Summary

Net Average Daily Production (Boe/d)

Net Average Daily Oil Production (Bo/d)

56,000 29,700

• - 63,000

• - 32,700

Production Costs ($ / Boe)

Lease Operating Expense

Gathering, Processing & Transportation

Depreciation, Depletion, Amortization

Cash General and Administrative1

Stock-based Compensation2

Severance and Ad Valorem Taxes (% of revenue)

$4.50 $3.00 $13.00 $1.95 $1.50

• - $5.10

• - $3.40

• - $15.00

• - $2.25

• - $2.00

  6.0%

• - 8.0%

Capital Expenditure Program ($MM)

Drilling, Completions & Facilities

Infrastructure, Land & Other

$250

• - $290

  10

• - 20

Total Capital Expenditures

$260

-$310

Operated Drilling Program

Wells Spud (Gross)

Wells Completed (Gross)

40 40

• - 46

• - 48

• (1) Cash general and administrative guidance does not include the portion of stock-based compensation that will settle in cash

• (2) Stock-based compensation guidance includes expense amounts for both equity awards and for cash-based liability awards. The amount of actual expense to be incurred for the liability awards included in this guidance range may vary from our forecast, as such expense can fluctuate materially in future periods with changes in Centennial's stock price and, for certain awards, with changes in Centennial's stock price performance versus a defined peer group of companies. A portion of these liability awards are expected to be paid in cash in FY 2021

Centennial 2.0: The Path Forward

✓

Added a second drilling rig and returned to normalized drilling activity levels

✓ Generated ~$30mm of free cash flow for the quarter

✓

Reaffirmed $700mm borrowing base and improved liquidity through revolver debt repayment

✓ Exited the year with low 30's decline rate percentage

✓ Established a FY 2021 hedge book that protects a baseline activity level while retaining commodity price upside

• ▪ Plan to operate a two-rig program

• ▪ Anticipate full-year average oil production slightly above Q4'20 levels

• ▪ Expect to generate $55 - 75mm of free cash flow in 2021 at current strip

  ⎯ Free cash flow positive down to a mid-$40's WTI price

• ▪ Maintain focus on the D&C and operating cost efficiencies realized in 2020

• ▪ Target < 2.5x leverage by year-end assuming current strip pricing

• ▪ Generate free cash flow down to a low-$40's / Bbl oil price environment

• ▪ Organically de-lever with a long-term target of < 1.5x

• ▪ Target mid to high single digit long-term oil production growth assuming supportive commodity prices

• ▪ Build scale organically through increases to free cash flow, EBITDAX and production over time

• ▪ Continue to evaluate opportunities to gain size, scale and further de-lever

Centennial 2.0: Final Thoughts

• ▪ High-Quality Asset Base

• ▪ Proven Operational Execution

• ▪ Sustained Well Cost Reductions

• ▪ Lower Unit Cost Structure

• ▪ Shallowing Corporate Decline Rate

• ▪ No Near-Term Debt Maturities

• ▪ Maintaining Solid Liquidity

Structural cost and operational improvements have improved capital efficiency and accelerated free cash flow profile

Appendix

Quarterly Financial Results

Financial Summary ($mm, unless otherwise noted)1

(1)

(2)

(3)Adjusted EBITDAX is not presented in accordance with generally accepted accounting principles in the United States 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 year and borrowing base in current year), less availability blocker and letters of credit

($ in millions, unless specified)	FY 2019	Q1	Q2	Q3	Q4	FY 2020
Average Daily Production (Boe/d)	76,072	71,820	68,245	68,934	59,708	67,161
Average Daily Oil Production (Bo/d)	42,692	41,512	37,411	35,292	30,196	36,084
% Oil	56%	58%	55%	51%	51%	54%
Financial highlights
Total Revenue	$944.3	$192.8	$90.5	$149.1	$148.1	$580.5
Pre-Hedge Realized Oil Price ($/Bbl)	$52.02	$45.14	$21.47	$36.95	$40.36	$36.02
Adjusted EBITDAX2	$604.2	$113.5	$24.4	$50.9	$79.1	$268.0
Net Income (loss)3	$15.8	($548.0)	$5.3	($51.5)	($88.7)	($682.8)
Unit Costs ($/Boe)
Lease Operating Expense	$5.26	$4.99	$4.16	$3.87	$4.78	$4.45
Gathering, Processing & Transportation	2.62	2.59	2.78	3.02	3.27	2.90
Severance & Ad Valorem Taxes	2.28	2.54	0.92	1.24	1.69	1.60
Cash G&A	1.90	1.99	2.21	1.94	1.96	2.03
Depreciation, Depletion & Amortization	16.00	15.49	14.98	14.10	13.62	14.59
Capital Expenditures Incurred
Drilling & Completion	$691.4	$146.8	$21.4	$19.7	$24.1	$212.0
Facilities, Infrastructure and Other	162.0	25.2	6.5	1.5	5.0	38.2
Land	38.4	3.4	0.1	0.3	0.8	4.6
Total Capital Expenditures	$891.8	$175.4	$28.0	$21.5	$29.9	$254.8
Cash and Cash Equivalents	$10.2	$3.8	$7.2	$5.2	$5.8	$5.8
Total Debt Outstanding4	$1,075.0	$1,135.0	$1,142.9	$1,127.9	$1,102.9	$1,102.9
Liquidity5	$634.5	$468.1	$297.2	$314.1	$339.7	$339.7
Amounts may not sum due to rounding

Crude Oil Hedge Position Overview

Hedge Position Overview (as of February 19, 2021)

FY 2021
Q1	Q2	Q3	Q4	2021
WTI Fixed Price Swaps
Total Volume (Bbl)	990,000	1,183,000	736,000	644,000	3,553,000
Daily Volume (Bbl/d)	11,000	13,000	8,000	7,000	9,734
Weighted Average Price ($ / Bbl)	$41.48	$43.18	$45.87	$45.59	$43.70
Brent Fixed Price Swaps
Total Volume (Bbl)	270,000	409,500	184,000	184,000	1,047,500
Daily Volume (Bbl/d)	3,000	4,500	2,000	2,000	2,870
Weighted Average Price ($ / Bbl)	$46.85	$54.98	$48.25	$48.50	$50.57
WTI Collars
Total Volume (Bbl)	315,000	227,500	92,000	92,000	726,500
Daily Volume (Bbl/d)	3,500	2,500	1,000	1,000	1,990
Weighted Average Floor ($ / Bbl)	$40.00	$42.00	$42.00	$42.00	$41.13
Weighted Average Ceiling ($ / Bbl)	$48.14	$51.14	$50.10	$50.10	$49.58
Mid-Cush Basis Swaps
Total Volume (Bbl)	990,000	1,183,000	736,000	644,000	3,553,000
Daily Volume (Bbl/d)	11,000	13,000	8,000	7,000	9,734
Weighted Average Price ($ / Bbl)	$0.01	$0.11	$0.26	$0.26	$0.14

Natural Gas Hedge Position Overview

Hedge Position Overview (as of February 19, 2021)

FY 2021
Q1	Q2	Q3	Q4	2021	Q1
Henry Hub Fixed Price Swaps
Total Volume (MMBtu)	5,400,000	3,640,000	3,680,000	3,680,000	16,400,000	1,800,000	1,800,000
Daily Volume (MMBtu/d)	60,000	40,000	40,000	40,000	44,932	20,000	4,932
Weighted Average Price ($ / MMBtu)	$2.91	$2.89	$2.89	$2.95	$2.91	$3.00	$3.00
Henry Hub Collars
Total Volume (MMBtu)	1,800,000	--	--	--	1,800,000	--	--
Daily Volume (MMBtu/d)	20,000	--	--	--	4,932	--	--
Weighted Average Floor ($ / MMBtu)	$2.90	--	--	--	$2.90	--	--
Weighted Average Ceiling ($ / MMBtu)	$3.64	--	--	--	$3.64	--	--
Waha Differential Basis Swaps
Total Volume (MMBtu)	1,800,000	3,640,000	3,680,000	3,680,000	12,800,000	1,800,000	1,800,000
Daily Volume (MMBtu/d)	20,000	40,000	40,000	40,000	35,068	20,000	4,932
Weighted Average Price ($ / MMBtu)	($0.30)	($0.30)	($0.30)	($0.28)	($0.29)	($0.26)	($0.26)

FY 2022 2022

Reconciliation of Adjusted EBITDAX to Net Income (Loss)

Adjusted EBITDAX reconciliation ($ thousands)1

($ in thousands, unless specified)	FY 2019	Q1	Q2	Q3	Q4	FY 2020
Net income (loss) attributable to Class A Common Stock	$15,798	($547,983)	$5,330	($51,529)	($88,655)	($682,837)
Net income (loss) attributable to noncontrolling interest	616	(2,362)	0	0	0	(2,362)
Interest expense	55,991	16,421	17,371	17,718	17,682	69,192
Income tax expense (benefit)	5,797	(83,208)	(1,916)	0	0	(85,124)
Depreciation, depletion and amortization	444,243	101,258	93,020	89,444	74,832	358,554
Impairment and abandonment expenses	47,245	611,300	19,425	19,904	40,561	691,190
Gain on exchange of debt	0	0	(143,443)	0	0	(143,443)
Non-cash derivative (gain) loss	(4,094)	8,452	22,963	(32,518)	18,987	17,884
Stock-based compensation expense2	26,315	5,892	4,270	4,772	8,111	23,045
Exploration and other expense	11,390	4,009	4,051	2,670	7,625	18,355
Workforce reduction severance payments	0	0	2,884	582	0	3,466
Transaction costs	0	0	476	0	0	476
(Gain) loss on sale of long-lived assets	857	(245)	2	(145)	(10)	(398)
Adjusted EBITDAX	$604,158	$113,534	$24,433	$50,898	$79,133	$267,998
Adjusted EBITDAX is a non-GAAP financial measure

(1) (2)Includes stock-based compensation for both equity and liability awards not yet settled in cash related to general and administrative employees only. Stock-based compensation for geographical and geophysical personnel is included with the Exploration and other expenses line item.

Reconciliation of Free Cash Flow to Operating Cash Flow

Free Cash Flow (Deficit) reconciliation ($ thousands)1

($ in thousands)	2020	2019	2020	2019
Net cash provided by operating activities	$41,144	$179,298	$86,873	$283,979
Changes in working capital:
Accounts receivable	$3,567	($37,673)	($8,507)	($12,653)
Prepaid and other assets	$979	$887	$3,845	$1,728
Accounts payable and other liabilities	$13,253	$729	$8,694	($13,493)
Discretionary cash flow	$58,943	$143,241	$90,905	$259,561
Less: total capital expenditures incurred	($29,900)	($197,100)	($51,400)	($409,200)
Free cash flow (deficit)	$29,043	($53,859)	$39,505	($149,639)
Free cash flow is a non-GAAP financial measure

Three Months Ended December 31,

Six Months Ended December 31,

(1)