Investor PresentationAUGUST 2021

NYSE:CRK

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Disclaimer

This presentation includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements give our current expectations or forecasts of future events. These statements include estimates of future natural gas and oil reserves, expected natural gas and oil production and future expenses, assumptions regarding future natural gas and oil prices, budgeted capital expenditures and other anticipated cash outflows, as well as statements concerning anticipated cash flow and liquidity, business strategy and other plans and objectives for future operations.

Our production forecasts are dependent upon many assumptions, including estimates of production decline rates from existing wells and the outcome of future drilling activity.

Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include the timing and extent of changes in market prices for oil and gas, operating risks, liquidity risks, including risks relating to our debt, political and regulatory developments and legislation, and other risk factors, including the impact of the current COVID-19 pandemic, and known trends and uncertainties as described in our Annual Report on Form 10-K for fiscal year 2020 and as updated and supplemented in our Quarterly Reports on Form 10-Q, in each case as filed with the Securities and Exchange Commission. Should one or more of these risks or uncertainties occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in the forward-looking statements.

Reserve engineering is a process of estimating underground accumulations of hydrocarbons that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions could impact Comstock’s strategy and change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered. These quantities do not necessarily constitute or represent reserves as defined by the Securities and Exchange Commission and are not intended to be representative of all anticipated future well results.

Comstock owns or has rights to various trademarks, service marks and trade names that we use in connection with the operation of our business. This presentation also contains trademarks, service marks and trade names of third parties, which are the property of their respective owners. The use or display of third parties’ trademarks, service marks, trade names or products in this presentation is not intended to, and does not imply, a relationship with, an endorsement or sponsorship by or of Comstock. Solely for convenience, the trademarks, service marks and trade names referred to in this presentation may appear without the ®. TM or SM symbols, but such references are not intended to indicate, in any way, that Comstock will not assert, to the fullest extend under applicable law, their rights or the right of the applicable licensor to these trademarks, service marks and trade names.

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Committed to environmental stewardship and a responsible energy future, with leadership on low emissions in a prolific natural gas basin

Best-in-class capital efficiency creates industry-leading margins and return on capital employed

Conservative operating plan and best-in-class cost structure drives unparalleled free cash flow for deleveraging

Basin leader in the Haynesville, a premier natural gas basin with geographical proximity to Gulf Coast and attractive price differentials

> 1,900 high-return net drilling locations in the Haynesville and Bossier to support successful development program

Strategic relationship with successful Dallas businessman Jerry Jones, the company's largest shareholder, whose investment to date in Comstock totals $1.1 billion

Why Invest in Comstock?

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Leading Haynesville Operator

Haynesville Shale

De Soto

Harrison

Panola

Sabine

Shelby

Caddo

Robertson

Bossier

Nacogdoches

San Augustine

RedRiver

Bienville

Bossier Shale

Net Acres(Haynesville / Bossier)

323,000(1) Q2 21 Production 1.4 Bcfe/d

Net Undrilled Locations >1,900 Proved Reserves 5.8 Tcfe(2)

% Held-by-Production 93% % Gas 99%

% Operated 91% PDP PV-10 $2.2 bn(2)

% Working Interest 82% Total PV-10 $4.4 bn(2)

• Significant Scale in the Haynesville• 323,000(1) Haynesville / Bossier net acres

• Robust inventory of de-risked, high-return drilling locations

• > 1,900 net drilling locations• 73% of locations >5,000 ft. laterals

• Industry leading margins with substantial free cash flow generation

• Low-cost, flexible gas marketing options

• Limited basis risk due to proximity and contracts tied to Henry Hub

• Low gathering, treating and transportation cost

• No unmet minimum volume commitments

Haynesville / Bossier shale

Company statistics

(1) As of December 31, 2020.

~

(2) Based oil and gas prices of $50 WTI / $2.75 HH.

Comstock Resources overview

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Recent Accomplishments and 2021 Outlook

• Successfully raised $1 billion of equity and debt throughout a volatile 2020• $207 million common equity in May to redeem the Series A preferred, eliminated $21 million of

annual distributions• Issued $800 million senior notes in 2020 to enhance liquidity and reduce reliance on bank facility• Refinanced $2 billion of senior notes in March and June 2021 saving $47.9 million in cash interest

payments per year and extending senior notes weighted average maturity from 4.7 years to 7.6 years

Prudently Managing the Balance Sheet

• Strong IP rates of 25 Mmcfe per day on average in 2020 and 2021• Grew proved reserve base by 3% at a low, all-in finding cost of $0.66 per Mcfe in 2020

• SEC Proved reserves grew to 5.6 Tcfe, replaced 159% of production• 1P PV-10 of $4.4 billion at flat $50 WTI / $2.75 HH

Exceptional Drilling Results and Reserves

Growth

• Drilling and completion costs per lateral foot reduced by 14% since 2019• Longer lateral wells averaged $1,042 per foot in 2021 versus $1,215 per foot in 2019

Consistently Low and Improving

Costs

• Focused on capital discipline, generating free cash flow, and deleveraging the balance sheet• Estimated production of ~1.4 Bcfe per day • Development capital expenditures of $525 to $560 million• Expecting to generate substantial free cash flow in 2021 to pay down debt

Disciplined 2021 Plan and Outlook

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Corporate Strategy Excels in Current Environment

Develop

Prudently grow free cash flow, production and reserves

through development of high-quality inventory

Enhance

Enhance returns on capital through a focus on optimizing

full-cycle economics

Acquire

Evaluate and pursue strategic acquisition opportunities to grow reserves, production,

and acreage position

Finance

Maintain disciplined financial strategy

Protect

Manage commodity price exposure through an active hedging program to protect

our expected future cash flows

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Haynesville vs. Appalachia

Lower midstream costs Superior full-cycle economics

Faster payouts Ample in-basin demand

Favorable differentials

Source: RSEG, Public filings. Appalachia includes AR, CNX, COG, EQT and RRC

(1) Based on RSEG type curves at $2.75 per Mcf.

2021 Q2 Gathering & Transportation ($/mcfe)

2020 EBITDAX Margin / 3-Year F&D2021 Q2 Differentials vs. Henry Hub ($/mcfe)

Haynesville Appalachia

Basin Demand

Access to Premium Markets

Under-supplied Over-supplied

Open, More Capacity in

Process

Nearly Full ex MVP / ACP

Basin Average Payback (Years)IRR (%)

Higher IRRs(1)

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Drilling Location Inventory

Extensive inventory of high return drilling locations > 30 years of operated inventory based on 2021 drilling program

As of June 30, 2021

(Gross) (Net) (Gross) (Net) (Gross) (Net)

up to 5,000 ft. 242 200 522 84 764 284 5,000 ft. to 8,000 ft. 353 277 203 60 556 337 8,000 ft to 11,000 ft 433 322 224 60 657 382

> 11,000 ft 71 54 8 3 79 57 1,099 853 957 206 2,056 1,060

(Gross) (Net) (Gross) (Net) (Gross) (Net)

up to 5,000 ft. 243 195 359 48 602 244 5,000 ft. to 8,000 ft. 377 324 88 14 465 338 8,000 ft to 11,000 ft 373 303 130 22 503 325

> 11,000 ft 37 29 1 - - - 1,030 852 578 84 1,570 907

Total 2,129 1,705 1,535 291 3,626 1,967

HaynesvilleOperated Non-Operated Total

BossierOperated Non-Operated Total

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$565$425 $451 $457 $365 $390

$941$1,021

$764$569

$651 $661

2017 2018 2019 2020 2021 Q1 2021 Q2Completion Drilling

$1,026

$1,446$1,506

$1,215

$1,016 $1,051

D&C Costs

($ per Lateral Foot)

(Laterals > 8,000 ft.)

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2021 YTD Drilling Results

56 7

8

9

17

Caddo

De Soto

Harrison

Red River

Bienville

Bossier

14

151623

1819

202122

Panola

2425

27

2829

26

3031

3334

35

3637

38

32

Sabine

Completed 306 operated wells since 2014 (average lateral length of 7,800 ft.) with average IP rate of 23 Mmcf/d

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1112 13

12

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Well NameLL

(feet)Turned To

SalesIP

(Mmcf/d)1 George DGH #1 11,545 01/26/2021 292 George DGH #2 11,219 01/26/2021 293 Jordan 16-9-4 #1 12,716 02/05/2021 264 Jordan 16-9-4 #2 8,245 02/05/2021 265 Beaubouef 15-10 #3 7,477 03/07/2021 306 Beaubouef 15-10 #4 5,431 03/07/2021 267 Beaubouef 15-10 #1 5,310 03/08/2021 258 Beaubouef 15-10 #2 7,444 03/08/2021 299 Roberts BF #1 11,132 03/10/2021 21

10 Roberts TTB #2 13,043 03/10/2021 3211 Adams 21-28-33 #1 10,573 04/12/2021 2312 Adams 21-28-33 #2 10,072 04/12/2021 2613 Curry 28-33 #1 9,733 04/14/2021 2314 Curry 28-33 #2 9,544 04/14/2021 2215 Davis 7-6 #1 5,997 04/14/2021 2516 Davis 7-6 #2 5,398 04/14/2021 2117 Davis 7-6 #3 4,568 04/14/2021 1918 Abercrombie Vincent H 1H 9,928 05/20/2021 2619 Abercrombie Abney H 1H 8,499 05/20/2021 2420 Abercrombie Vincent H 2H 9,936 05/22/2021 2321 Abercrombie Vincent H 3H 9,969 05/22/2021 2522 Abercrombie Vincent H 4H 11,388 05/22/2021 1623 Renrew Lands 5-32-29 HC 1 10,567 06/06/2021 2524 Renrew Lands 5-32-29 HC 2 10,251 06/06/2021 2625 Edgar 31-30 HC 1 9,362 06/06/2021 2026 Edgar 31-30 HC 2 9,061 06/06/2021 2227 Headrick 14-11 HC 3 9,817 07/06/2021 2428 Headrick 23 HZ 1 4,581 07/06/2021 1529 Headrick 14-23 HC 3 5,317 07/06/2021 1730 Hart 14-11 HC 1 9,825 07/09/2021 2431 Hart 14-11 HC 2 9,817 07/09/2021 2432 Hart HZ 2 4,580 07/09/2021 1533 Greene 22-15-10 HC 1 7,921 07/18/2021 1834 Weyerhauser 15-10 HC 2 6,073 07/19/2021 2235 Weyerhauser 15-10 HC 3 5,477 07/19/2021 2236 Arrington 11-14 HC 1 7,483 07/22/2021 3137 Arrington 11-14 HC 2 7,514 07/22/2021 3238 Weyerhauser 15-10 HC 1 5,902 07/23/2021 23

8,493 24

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Favorable Natural Gas Supply Demand Dynamics

Favorable Supply & Demand

Fundamentals

• Long-term price support expected from continued sector capital discipline, increased power generation demand, long-term industrial demand and continued coal/nuclear retirements

• Appalachian gas pipeline constraints limit long-term growth prospects

• Natural gas storage levels are below average as we enter summer demand season

Strong Export

Markets

• LNG exports have reached record levels• Average of 10.4 Bcf/d for 2021 YTD,

with maximum flow rate of 11.9 Bcf/d• Additional capacity of 4.4 Bcf/d is

currently under construction• Mexican exports continue to grow

• Average of 6.5 Bcf/d for 2021 YTD, with maximum flow rate of 8 Bcf/d

Natural Gas Storage (as of 7/30/21)

542 Bcfbelow

Last Year

185 Bcfbelow

5 Yr. Average

Natural Gas Exports

Source: EIA , Bloomberg and Criterion Research.

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Carthage

Perryville

Henry HubHSC

Gillis

LNG & Industrial Demand Centers

Gas Marketing Overview

High margins supported by gas marketing arrangements…

• No firm transportation agreements at out-of-market rates

• 40% of natural gas is sold in premium Gulf Coast markets

• Increasing to 60% when new Haynesville Acadian Extension is in service (Q4 2021)

• New lateral in service in Q2 which supports up to 250 Mmcf/day to flow from Logansport to Acadian

• Will have 1 Bcf per day capacity on Acadian

• Potential to improve sales price realization for any gas redirected from current Perryville market by ~10¢ per Mcf

Improving direct access to gulf coast demand centers

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Best-in-class cost structure of gas producers

Leading margins compare favorably to both Permian and gas-weighted names

Cost Structure Drives Best-in-Class EBITDAX Margin

Source: Public filings. Based on Q2’21 reported actuals. Gas peers include: AR, CHK, CNX, COG, GDP, GPOR, EQT, RRC, SBOW and SWN. OIL peers include: FANG, LPI and PXD.(1) See non-GAAP reconciliation in appendix.

$ /

Mcf

eU

nhed

ged

EBIT

DAX(1

)

Mar

gin

(%)

Gas PeersOil Peers

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Cost structure of gas producers including interest

Operating Cost Structure Offsets Legacy Interest Cost$

/ M

cfe

5¢ Improvement

Source: Public filings. Based on Q2’21 reported actuals. Gas peers include: AR, CHK, CNX, COG, GDP, GPOR, EQT, RRC, SBOW and SWN.

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Unhedged Margin and Profits Per Mcfe N

YMEX

Gas

Pric

e(P

er M

cf)

$2.50

$3.00

$3.50

$4.00

$1.31 (52%)

Margin per Mcfe Pre-Tax Profits per McfeCo

sts

(Per

Mcf

e)

$1.81 (60%)

$2.31 (66%)

$2.81 (70%)

$0.72

$1.22

$1.72

$2.22

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Best-in-Class Margins Deliver Strong Returns

Low and Efficient Corporate Overhead(Lowest of All E&P Companies)

Higher Realizations due to Favorable Gulf Coast Market

Operational Scale as Haynesville Basin’s Largest Producer

Comstock’s Margin Advantage

Return on Capital Employed (2020)

EBITDAX Margin (2020)

Source: Public filings. Note: EBITDAX Margin reflects hedged margin. ROCE calculated as NOPAT / Average Capitalization.

Favorable Midstream Rates due to No Above Market Contracts

Low Haynesville Lifting Costs(No Treating/Compression)

U.S. E&P Universe

U.S. E&P Universe

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Drilling Program

($ in millions)

Developmental Capital Expenditures $525 million to $560 millionLeasing Program $15 million to $20 millionWells Drilled to Total Depth - Operated 67 Gross / 55.2 NetWells to Sales - Operated 55 Gross / 47.6 NetYear-End Drilled Uncompleted Wells 31 Gross / 25.0 Net

2021 Drilling Program Overview

Average AverageLateral Gross WI Net Lateral Gross WI Net

$ (feet) Wells Wells $ (feet) Wells Wells

2020 wells turned to sales 24.0$ 10,143 8 7.4 99.8$ 9,712 18 16.5 2021 wells turned to sales 29.4 7,963 8 6.8 54.9 7,963 8 6.8 2021 wells drilled 95.6 8,459 21 15.7 144.4 7,887 34 26.7 2021 wells drilling 4.9 12,360 5 4.3 5.0 12,360 5 4.3 2021 non-operated and other 10.9 23.7 Total Development Costs 164.8$ 327.9$

Exploratory Leasing 7.6$ 13.4$

Second Quarter 2021 Six Months 2021

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Balance SheetBank Credit Facility

Senior Secured Revolving Credit Facility:• $1.4 billion borrowing base

reaffirmed on April 16, 2021• Maturity date July 16, 2024• Pricing of L+225 to 325 bpts• Key financial covenants:

• Leverage Ratio < 4X, Current Ratio >1.0

Capitalization

Debt Maturity Profile

($ in millions) 6/30/2021

Cash and Cash Equivalents $20

Revolving Credit Facility $4757½% Senior Notes due 2025 244 6¾% Senior Notes due 2029 1,250 5⅞% Senior Notes due 2030 965 Total Debt $2,934

Preferred Equity (at face value) $175Common Equity 947 Total Capitalization $4,056

Liquidity $945

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Combination of Comstock and Covey Park created the Haynesville leader with deep Tier 1 drilling inventory and peer-leading cost structure

Expect to generate meaningful Free Cash Flow to reduce revolver borrowings

Industry leading margins and returns on capital employed

~69% hedged in 2021

Focused on capital discipline and deleveraging the balance sheet

Equitized $210 million of convertible preferred stock and refinanced $2 billion of senior notes which reduced annual fixed charges by $68.9 million

Bank facility matures in 2024

Weighted average senior note maturity of 7.6 years

Financial liquidity of $900+ million

Clear line of sight to reducing leverage

Significant Scale

Sustainable, Low Cost,

and Hedged Business Model

Maximizing Free Cash

Flow

Favorable Maturity Runway

Improved Liquidity

Improving Credit Profile

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Strong Focus on ESG

Environmental GovernanceSocial

Utilizing cleaner burning natural gas rather than diesel fuel to reduce emissions in our drilling and completion operations.

Our active leak detection and repair program uses optical gas imaging technology to detect leaks so they are repaired immediately.

We have improved our completion designs to reduce our freshwater use volumes for hydraulic fracturing by approximately 30%.

We utilize multi-well pad locations and strive to extend the lateral lengths of our wells to minimize our above-ground footprint.

Comstock strives to maintain sustainable and safe business practices and is committed to conducting business in a responsible manner that protects the environment along with the health, safety and security of employees, contractors and the communities where it operates.

Our Employee Health & Safety Management System is designed to achieving our goals of operational excellence and maintaining an injury free workplace. Components include intensive employee training, periodic audits and inspection and scorecards to measure our success.

We hold our contractors accountable to the highest performance standards for employee safety programs, policies and procedures, including training and we monitor compliance with a third party management service.

Our OSHA Total Recordable Incident Rate was 0.00 in 2018 and 2019 and 0.45 in 2020.

Despite being a controlled company, we maintain a majority of independent directors who comprise our three oversight committees –Audit, Compensation and Governance/Nominating.

Our bonus incentive plan no longer focuses on absolute growth metrics and instead has performance measures for Return on Equity, Free Cash Flow Generation, Well Cost Efficiency, Operating Efficiency and Reserve Replacement as its primary performance metrics.

We have strong governance policies in place over stock ownership, non-discrimination, anti-harassment and bribery.

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Lowering GHG Intensity

Emis

sion

Inte

nsity

(k

g CO

2e /

boe

)

2019 data includes operations of Covey Park Energy for the full year.

Emission Intensity

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Natural Gas Powered Completions Comstock has partnered with BJ Energy Solutions to deploy BJ’s next generation fracturing fleet which is fueled by

100% natural gas in its Haynesville shale development program in early 2022

BJ’s TITAN solution will make a substantial contribution toward Comstock’s CO2e and Methane reduction goals while also improving well economics

BJ’s TITAN Fleet supports the reduction of greenhouse gas emissions while also creating efficiencies including reduced operating costs, improved mobility, smaller well pad sites, and improved operational reliability

Carbon emissions (CO2e) are reduced by 25% compared to conventional diesel-powered fracturing equipment

This technology allows Comstock to reduce Methane emissions by ~60% compared to diesel only powered equipment, and by greater than 95% compared to dual fuel options

The TITAN Fleet is comprised of only 8 pumps versus the 18 conventional pumps required for a typical Comstock completion today, representing a +30% reduction of pad space required

The TITAN Fleet meets the most stringent noise requirements across North America

The three year contract with BJ locks in current completion cost while providing additional cost saving efficiencies, all while reducing the environmental impact of Comstock’s future well completions

5,000 HHP direct drive natural gas fired turbine pumping units – 8 units delivering 40,000 HHP

Appendix

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Hedging Program

(1) The counterparty has the right to exercise a call option to enter into a price swap with the Company on 120,000 MmBtu/d in 2022 at an average price of $2.51. The call option expires for 100,000 Mmbtu/d at an average price of $2.52 in October 2021 and 20,000 Mmbtu/d at an average price of $2.50 in November 2021.

Comstock has ~70% of its oil and gas production hedged in 2H 2021

Period

2021 3Q 585,000 $2.53 400,000 $2.47 / $3.03 985,000 1,500 $41.67 / $51.672021 4Q 560,000 $2.53 406,630 $2.48 / $3.05 966,630 1,500 $41.67 / $51.672021 2H 572,500 $2.53 403,315 $2.48 / $3.04 975,815 1,500 $41.67 / $51.67

2022 1Q 250,000 $2.70 350,000 $2.59 / $3.72 600,000 120,000 $2.512022 2Q 200,000 $2.78 340,000 $2.52 / $3.44 540,000 120,000 $2.512022 3Q 200,000 $2.78 290,000 $2.53 / $3.47 490,000 120,000 $2.512022 4Q 200,000 $2.78 290,000 $2.53 / $3.48 490,000 120,000 $2.512022 FY 212,329 $2.76 317,260 $2.54 / $3.53 529,589 120,000 $2.51

2023 FY 12,329 $2.50 / $3.67 12,329

Natural Gas (Mmbtu/d) Oil (Bbl/d)

Swaps Collars Total Swaptions 1 Collars

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Guidance

2Guidance 2021

Production (Mmcfe/d) 1,330 - 1,425

% Natural Gas 97% - 99%

Development Capital Expenditures ($MM) $525 - $560Leasing Program ($MM) $15 - $20

Expenses ($/Mcfe) - Lease Operating $0.21 - $0.25 Gathering & Transportation $0.23 - $0.27 Production & Other Taxes $0.08 - $0.10 DD&A $0.90 - $1.00 Cash G&A $0.05 - $0.07

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Non-GAAP Financial Measure

2

In thousands 6M 2021 6M 2020 2020 2019EBITDAX: Net Income (Loss) (313,820)$ (7,848)$ (52,417)$ 96,889$ Interest Expense 121,252 104,811 234,829 161,541 Income Taxes (98,144) (54) (9,210) 27,803 Depreciation, Depletion and Amortization 230,574 213,772 417,112 276,526 Unrealized Losses from Hedges 217,894 49,102 124,545 949 Exploration - 27 27 241 Stock-based Compensation 3,489 2,982 6,464 4,020 Loss on Early Extinguishment of Debt 352,599 861 861 - Covey Park July 2019 Hedging Settlements - - - 4,574 Covey Park Transaction Costs - - - 41,010 Loss (Gain) on Sale of Assets (79) - (17) 25 Total EBITDAX 513,765$ 363,653$ 722,194$ 613,578$

Reconciliation of Adjusted EBITDAX