Investor Presentation - NYSE:CRK - Comstock Resources, Inc.
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NYSE:CRK
Investor Presentation
MAY 2021
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.
2
Why Invest in Comstock?
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
program
Committed to environmental stewardship and a responsible energy future, with leadership on
low emissions in a prolific natural gas basin
Strategic relationship with successful Dallas businessman Jerry Jones, the company's largest
shareholder, whose investment to date in Comstock totals $1.1 billion
3
Leading Haynesville Operator
Comstock Resources overview Haynesville / Bossier shale
Haynesville Shale
• Significant Scale in the Haynesville Harrison
Bossier
• 323,000 Haynesville / Bossier net acres
(1)
Caddo
Bienville
• Robust inventory of de-risked, high-
return drilling locations
• > 1,900 net drilling locations Robertson
De Soto
Red
River
Panola
• ~73% of locations >5,000 ft. laterals
• Industry leading margins with
substantial free cash flow generation
Nacogdoches Shelby
Sabine Bossier
Shale
• Low-cost, flexible gas marketing
options San
• Limited basis risk due to proximity and Augustine
contracts tied to Henry Hub Company statistics
• Low gathering, treating and Net Acres
323,000(1) Q1 21 Production 1.3 Bcfe/d
transportation cost (Haynesville / Bossier)
Net Undrilled Locations 1,930 Proved Reserves 5.8 Tcfe(2)
• No unmet minimum volume
commitments % 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)
(1) As of December 31, 2020. (2) Based oil and gas prices of $50 WTI / $2.75 HH.
4
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
Prudently annual distributions
Managing the • Issued $800 million senior notes in 2020 to enhance liquidity and reduce reliance on bank facility
Balance Sheet • Refinanced $1,152 million of senior notes in March 2021 which saves $19.5 million in cash
interest payments per year and extends senior notes weighted average maturity from 4.9 years
to 6.7 years
Exceptional • Strong IP rates of 25 Mmcfe per day on average in 2020 and 2021
Drilling Results • Grew proved reserve base by 3% at a low, all-in finding cost of $0.66 per Mcfe in 2020
and Reserves • SEC Proved reserves grew to 5.6 Tcfe, replaced 159% of production
Growth • 1P PV-10 of $4.4 billion at flat $50 WTI / $2.75 HH
Consistently Low • Drilling and completion costs per lateral foot reduced by 17% since 2019
and Improving • Longer lateral wells averaged $1,010 per foot in 2021 Q1 versus $1,215 per foot in 2019
Costs
• Comstock’s focus continues to be capital discipline, producing free cash flow, and deleveraging
the balance sheet
Disciplined 2021 • Estimated production of 1.3 to 1.4 Bcfe per day
Plan and Outlook • Development capital expenditures of $510 to $550 million
• Expecting to generate substantial free cash flow in 2021 to pay down debt
5
Corporate Strategy Excels in Current Environment
Develop
Prudently grow free cash flow,
production and reserves
through development of high-
quality inventory
Protect Enhance
Manage commodity price
Enhance returns on capital
exposure through an active
through a focus on optimizing
hedging program to protect
full-cycle economics
our expected future cash flows
Finance Acquire
Evaluate and pursue strategic
Maintain disciplined financial acquisition opportunities to
strategy grow reserves, production,
and acreage position
6
Haynesville vs. Appalachia
Favorable differentials Lower midstream costs Superior full-cycle economics
2021 Q1 Differentials vs. Henry Hub 2021 Q1 Gathering & Transportation 2020 EBITDAX Margin / 3-Year F&D
($/mcfe) ($/mcfe)
Higher IRRs (1)
Faster payouts Ample in-basin demand
Basin Average Payback (Years)
IRR (%) Haynesville Appalachia
Basin Under-
Over-supplied
Demand supplied
Access to Open, More
Nearly Full ex
Premium Capacity in
MVP / ACP
Markets Process
Source: RSEG, Public filings. Appalachia includes AR, CNX, COG, EQT and RRC
(1) Based on RSEG type curves at $2.75 per Mcf.
7
Drilling Location Inventory
Extensive inventory of high return drilling locations
33 Years of inventory based on 2021 drilling program
As of March 31, 2021
Haynesville
Operated Non-Operated Total
(Gross) (Net) (Gross) (Net) (Gross) (Net)
up to 5,000 ft. 245 201 535 81 780 282
5,000 ft. to 8,000 ft. 372 280 206 40 578 320
> 8,000 ft. 518 372 228 35 746 407
1,135 853 969 156 2,104 1,009
Bossier
Operated Non-Operated Total
(Gross) (Net) (Gross) (Net) (Gross) (Net)
up to 5,000 ft. 238 190 371 53 609 243
5,000 ft. to 8,000 ft. 407 334 98 9 505 343
> 8,000 ft. 407 323 132 12 539 335
1,052 847 601 74 1,653 921
Total 2,187 1,700 1,570 230 3,757 1,930
8
Improving D&C Costs
17% decrease from 2019 to 2021 due to increased drilling efficiency and lower service costs
(Laterals > 8,000 ft.)
($ per Lateral Foot)
$1,506
$1,446
$1,215
$1,026 $1,010
$941
$1,021
$764
$569
$645
$565
$425 $451 $457
$365
2017 2018 2019 2020 2021 Q1
Completion Drilling
9
Drilling Results
Bossier
Completed 285 operated wells since 2014
(average lateral length of 7,800 ft.)
with average IP rate of 24 Mmcf/d Caddo
6
5
12 11
First Quarter 2021: LL Turned To IP 13 Bienville
Well Name (feet) Sales (Mmcf/d)
1 Beaubouef 15-10 #3 7,477 03/07/2021 30 Harrison 1 4
2 Beaubouef 15-10 #4 5,431 03/07/2021 26 2 3
3 Beaubouef 15-10 #1 5,310 03/08/2021 25
4 Beaubouef 15-10 #2 7,444 03/08/2021 29
5 Roberts BF #1 11,132 03/10/2021 21 Red
6 Roberts TTB #2 13,043 03/10/2021 32 River
7 Adams 21-28-33 #1 10,573 04/12/2021 23 De Soto
8 Adams 21-28-33 #2 10,072 04/12/2021 26
8 9
9 Curry 28-33 #1 9,733 04/14/2021 23 7 10
10 Curry 28-33 #2 9,544 04/14/2021 23
11 Davis 7-6 #1 5,997 04/14/2021 25
12 Davis 7-6 #2 5,398 04/14/2021 21
13 Davis 7-6 #3 4,568 04/14/2021 19
8,132 25
10Favorable Natural Gas Supply Demand Dynamics
• Long-term price support expected from
Natural Gas Storage (as of 5/7/21)
continued sector capital discipline,
increased power generation demand, long-
Favorable term industrial demand and continued
Supply & coal/nuclear retirements
Demand • Appalachian gas pipeline constraints limit
Fundamentals long-term growth prospects
• Natural gas storage levels are below average
as we enter summer demand season 378 Bcf 72 Bcf
below below
Last Year 5 Yr. Average
Natural Gas Exports
• LNG exports have reached record levels
Strong • Average of 10.5 Bcf/d for 2021 YTD,
Export with max flow rate of 11.6 Bcf/d
Markets • Mexican exports continue to grow
• 6.3 Bcf/d for 2021 YTD
11Gas Marketing Overview
Improving direct access to gulf coast demand centers Improving margins by…
• Having minimal firm transportation
agreements, at out-of-market rates
Carthage
Perryville • Entering into medium-term sales
agreements, which provide basis pricing
certainty at the Perryville hub
• Redirecting natural gas from Perryville
hub to gain direct access to high-growth
Gulf Coast demand (industrial, refining,
chemical and LNG)
• New lateral in service in Q2 which
allows up to 250 Mmcf/day to flow
from Logansport to Acadian
• Entered into agreement to be major
shipper on new Haynesville Acadian
Extension for 1 Bcf/day (expected to
Gillis be in service by 4Q in 2021)
• Expect regional basis to tighten as ~4 Bcf
HSC LNG & Industrial Henry Hub of new North-to-South pipelines are
Demand Centers
projected to come on-line through 2022*
*BTU Analytics’ Gas Basis Outlook
12Cost Structure Drives Best-in-Class EBITDAX Margin
$ / Mcfe
Best-in-class cost structure of gas producers
Leading margins compare favorably to both Permian and gas-weighted names
Unhedged EBITDAX(1)
Margin (%)
Oil Peers
Gas Peers
Source: Public filings. Based on Q1’21 reported actuals. Gas peers include: AR, CHK, CNX, COG, GDP, GPOR, EQT, RRC, SBOW, SWN and VEI (Pro Forma). OIL peers include: FANG, LPI and PXD.
(1) See non-GAAP reconciliation in appendix.
13Operating Cost Structure Offsets Legacy Interest Cost
Cost structure of gas producers including interest
$ / Mcfe
Source: Public filings. Based on Q1’21 reported actuals. Gas peers include: AR, CHK, CNX, COG, GDP, GPOR, EQT, RRC, SBOW, SWN and VEI (Pro Forma).
* Pro Forma for the March 4th Refinancing Transaction.
14Best-in-Class Margins Deliver Strong Returns
EBITDAX Margin (2020)
Comstock’s Margin Advantage
Operational Scale as Haynesville Basin’s
Largest Producer
U.S. E&P
Universe
Higher Realizations due to Favorable Gulf
Coast Market
Favorable Midstream Rates due to No Above Return on Capital Employed (2020)
Market Contracts
Low and Efficient Corporate Overhead
(Lowest of All E&P Companies)
U.S. E&P
Universe
Low Haynesville Lifting Costs
(No Treating/Compression)
Source: Public filings. Note: EBITDAX Margin reflects hedged margin. ROCE calculated as NOPAT / Average Capitalization.
15Oil & Natural Gas Reserves
(1)
Oil Gas Total
MBbls Bcf Bcfe
Proved Reserves as of 12/31/19(1) 16,747 5,342 5,442
Production (1,508) (451) (460)
2020 Additions 2 366 366
Price Revisions (2,858) (68) (86)
Performance Revisions (1,383) 375 367
Proved Reserves as of 12/31/20 (SEC)(1) 11,000 5,563 5,629
SEC PV 10 Value (million $) $1,991
8.2
PV 10 Value (million $) at $2.75/$50 $4,357
*Based on NYMEX prices of $2.75 per Mcf for natural gas and $50 per barrel for oil.
Reserves by Type PV-10 by Type Reserves by Commodity Reserves by Region
Total: Total:
Total: Total:
16
5.6 5.6
$2.0 Bn 5.6
Tcfe Tcfe
Tcfe
(1) Proved Reserves are based on SEC Pricing.
16Drilling Program
First Quarter 2021
Average
Lateral Gross WI Net
($ in millions) $ (feet) Wells Wells
2020 wells turned to sales $ 49.3 9,356 10 9.0
2020 wells completion In process 26.5 10,072 9 8.4
2021 wells drilled 61.1 7,351 21 19.0
2021 wells drilling 13.4 7,500 7 6.4
2021 non-operated and other 12.7
Total Development Costs $ 163.1
Exploratory Leasing $ 5.8
2021 Drilling Program Overview
Developmental Capital Expenditures $510 million to $550 million
Leasing Program $7 million to $10 million
Wells Drilled to Total Depth - Operated 67 Gross / 56.0 Net
Wells to Sales - Operated 55 Gross / 49.0 Net
Year-End Drilled Uncompleted Wells 31 Gross / 24.4 Net
Wells Drilling at Year-End 6 Gross / 5.7 Net
17Balance Sheet
Bank Credit Facility Capitalization
($ in millions) 3/31/2021
Cash and Cash Equivalents $77
Senior Secured Revolving Credit Facility: Revolving Credit Facility $550
7.50% Senior Notes due 2025 244
• $1.4 billion borrowing base
9.75% Senior Notes due 2026 873
reaffirmed on April 16, 2021 6.75% Senior Notes due 2029 1,250
• Maturity date July 16, 2024 Total Debt $2,917
• Pricing of L+225 to 325 bpts Preferred Equity (at face value) $175
Common Equity 1,130
• Key financial covenants: Total Capitalization $4,222
• Leverage Ratio < 4X, Current Ratio >1.0
Liquidity $927
Debt Maturity Profile
$1,250
$850 $873
$244
$550
2021 2022 2023 2024 2025 2026 2027 2028 2029
RBL Outstanding RBL Availability 7.50% Senior Notes 9.75% Senior Notes 6.75% Senior Notes
18Improving Credit Profile
Significant Combination of Comstock and Covey Park created the Haynesville leader with
Scale deep Tier 1 drilling inventory and peer-leading cost structure
Sustainable,
Expect to generate meaningful Free Cash Flow to reduce revolver borrowings
Low Cost,
and Hedged Industry leading margins and returns on capital employed
Business ~69% hedged in 2021
Model
Maximizing Focused on capital discipline and deleveraging the balance sheet
Free Cash
Equitized $210 million of convertible preferred stock and refinanced $1,152
Flow million of senior notes which reduced annual fixed charges by $40.5 million
Favorable Bank facility matures in 2024
Maturity
Weighted average senior note maturity of 6.7 years
19
Runway
Improved Financial liquidity of $900+ million
Liquidity Clear line of sight to reducing leverage
19Strong Focus on ESG
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.
Environmental Social Governance
We utilize natural gas fueled rigs Our Employee Health & Safety
Despite being a controlled
in our drilling operations. Using Management System is designed
company, we maintain a
cleaner burning natural gas to achieving our goals of
majority of independent
rather than diesel fuel allows us operational excellence and
directors who comprise our
to reduce emissions. maintaining an injury free
three oversight committees –
workplace. Components include
Audit, Compensation and
Our active leak detection and intensive employee training,
Governance/Nominating.
repair program uses optical gas periodic audits and inspection
imaging technology to detect and scorecards to measure our Our bonus incentive plan no
leaks so they are repaired success. longer focuses on absolute
immediately. growth metrics and instead has
We hold our contractors
performance measures for
We have improved our accountable to the highest
Return on Equity, Free Cash Flow
completion designs to reduce performance standards for
Generation, Well Cost Efficiency,
our freshwater use volumes for employee safety programs,
Operating Efficiency and Reserve
hydraulic fracturing by policies and procedures,
Replacement as its primary
approximately 30%. including training and we
performance metrics.
monitor compliance with a third
We utilize multi-well pad party management service.
locations and strive to extend We have strong governance
the lateral lengths of our wells to policies in place over stock
Our OSHA Total Recordable
minimize our above-ground ownership, non-discrimination,
Incident Rate was 0.00 in 2018
footprint. anti-harassment and bribery.
and 2019 and 0.45 in 2020.
20Lowering GHG Intensity
Emission Intensity
Emission Intensity
(kg CO2e / boe)
2019 data includes operations of Covey Park Energy for the full year.
21Natural 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
22Appendix
Guidance
Guidance 2021 2
Production (Mmcfe/d) 1,330 - 1,425
% Natural Gas 97% - 99%
Development Capital Expenditures ($MM) $510 - $550
Leasing Program ($MM) $7 - $10
Expenses ($/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
24Strong Hedging Program
Comstock has ~69% of its oil and gas production hedged in 2021
Natural Gas (Mmbtu/d) Oil (Bbl/d)
Period Swaps Collars Total 1 Swaptions 2 Collars
2021 1Q 607,271 $2.56 270,000 $2.45 / $2.88 877,271 $2.52 1,328 $41.23 / $51.10
2021 2Q 592,184 $2.54 330,000 $2.46 / $2.99 922,184 $2.51 1,500 $41.67 / $51.67
2021 3Q 585,000 $2.53 400,000 $2.47 / $3.03 985,000 $2.51 1,500 $41.67 / $51.67
2021 4Q 560,000 $2.53 400,000 $2.47 / $3.03 960,000 $2.50 1,500 $41.67 / $51.67
2021 FY 585,981 $2.54 350,493 $2.46 / $2.99 936,474 $2.51 1,458 $41.57 / $51.54
2022 1Q 190,000 $2.62 180,000 $2.51 / $3.27 370,000 $2.57 120,000 $2.51
2022 2Q 130,000 $2.68 120,000 $2.50 / $3.17 250,000 $2.59 120,000 $2.51
2022 3Q 130,000 $2.68 70,000 $2.50 / $3.10 200,000 $2.61 120,000 $2.51
2022 4Q 130,000 $2.68 70,000 $2.50 / $3.10 200,000 $2.61 120,000 $2.51
2022 FY 144,795 $2.66 109,589 $2.51 / $3.19 254,384 $2.59 120,000 $2.51
(1) Weighted average price is calculated using the long put price for collars.
(2) 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.
25Non-GAAP Financial Measure
Reconciliation of Adjusted EBITDAX
In thousands 1Q 2021 1Q 2020 2020 2019
EBITDAX:
Net Income (Loss) $ (134,125) $ 42,028 $ (52,417) $ 96,889
Interest Expense 63,811 52,810 234,829 161,541
Income Taxes (29,967) 11,391 (9,210) 27,803
Depreciation, Depletion and Amortization 109,128 110,425 417,112 276,526
Unrealized Loss (Gain) from Hedges 13,072 (16,483) 124,545 949
Exploration - 27 27 241
Stock-based Compensation 1,690 1,430 6,464 4,020
Loss on Early Extinguishment of Debt 238,539 - 861
2
-
Covey Park July 2019 Hedging Settlements - - - 4,574
Transaction Costs - - - 41,010
Loss (Gain) on Sale of Properties (70) - (17) 25
Total EBITDAX $ 262,078 $ 201,628 $ 722,194 $ 613,578
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