UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
☒
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2026
or
☐
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File No. 001-03262
COMSTOCK RESOURCES, INC.
(Exact name of registrant as specified in its charter)
Nevada
94-1667468
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification Number)
5300 Town and Country Blvd., Suite 500, Frisco, Texas 75034
(Address of principal executive offices)
Telephone No.: (972) 668-8800
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Trading Symbol(s)
Name of each exchange on which registered
Common Stock, par value $0.50 (per share)
CRK
New York Stock Exchange
New York Stock Exchange Texas
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer", "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer ☒
Accelerated filer ☐
Non-accelerated ☐
Smaller reporting company ☐
Emerging growth company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes ☐ No ☒
The number of shares outstanding of the registrant's common stock, par value $0.50, as of July 29, 2026 was 293,620,548.
QUARTERLY REPORT
For the Quarter Ended June 30, 2026
INDEX
Page
PART I. Financial Information
Item 1. Financial Statements (Unaudited):
Consolidated Balance Sheets as of June 30, 2026 and December 31, 2025
4
Consolidated Statements of Operations – for the three months and six months ended June 30, 2026 and 2025
5
Consolidated Statements of Stockholders' Equity – for the three months and six months ended June 30, 2026 and 2025
6
Consolidated Statements of Cash Flows – for the six months ended June 30, 2026 and 2025
7
Notes to Consolidated Financial Statements
8
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
20
Item 3. Quantitative and Qualitative Disclosure About Market Risk
25
Item 4. Controls and Procedures
26
PART II. Other Information
Item 1. Legal Proceedings
27
Item 1A. Risk Factors
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Item 3. Defaults upon Senior Securities
Item 4. Mine Safety Disclosures
Item 5. Other Information
Item 6. Exhibits
SIGNATURES
28
2
PART 1 — FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS (UNAUDITED)
3
CONSOLIDATED BALANCE SHEETS
As of
June 30,2026
December 31,2025
(Unaudited)
(In thousands)
ASSETS
Cash and cash equivalents
$
45,008
23,930
Accounts receivable:
Natural gas and oil sales and gas services
133,162
203,549
Joint interest operations
44,200
35,400
From affiliates
3,231
3,596
Derivative financial instruments
53,156
19,206
Other current assets
59,804
75,257
Total current assets
338,561
360,938
Property and equipment:
Natural gas and oil properties, successful efforts method:
Proved
9,719,655
8,984,969
Unproved
414,610
391,065
Other
477,395
386,656
Accumulated depreciation, depletion and amortization
(3,855,346
)
(3,547,196
Net property and equipment
6,756,314
6,215,494
Goodwill
335,897
22,230
—
Operating lease right-of-use assets
71,684
94,733
7,524,686
7,007,062
LIABILITIES AND STOCKHOLDERS' EQUITY
Accounts payable
503,111
501,695
Accrued costs
171,187
153,248
Operating leases
37,598
46,937
27,636
Total current liabilities
711,896
729,516
Long-term debt
3,098,770
2,809,066
Deferred income taxes
495,428
437,098
Long-term operating leases
33,570
47,692
Reserve for future abandonment costs
21,444
20,787
Total liabilities
4,361,108
4,044,159
Commitments and contingencies
Stockholders' equity:
Common stock—$0.50 par, 400,000,000 shares authorized, 293,620,548 and 293,054,806 shares issued and outstanding at June 30, 2026 and December 31, 2025, respectively
146,810
146,527
Additional paid-in capital
1,191,881
1,376,053
Accumulated earnings
1,240,446
1,124,230
Total stockholders' equity attributable to the Company
2,579,137
2,646,810
Noncontrolling interest
584,441
316,093
Total stockholders' equity
3,163,578
2,962,903
The accompanying notes are an integral part of these statements.
CONSOLIDATED STATEMENTS OF OPERATIONS
Three Months EndedJune 30,
Six Months EndedJune 30,
2026
2025
(In thousands, except per share amounts)
Revenues:
Natural gas sales
287,745
339,225
706,020
751,511
Oil sales
476
741
1,234
1,443
Total natural gas and oil sales
288,221
339,966
707,254
752,954
Gas services
63,481
130,296
229,982
230,162
Gain on sale of assets
1,580
3,400
Total revenues and other operating income
353,282
470,262
940,636
983,116
Operating expenses:
Production and ad valorem taxes
7,196
10,555
17,621
21,734
Gathering and transportation
43,331
41,759
85,135
84,376
Lease operating
28,150
31,109
56,431
66,109
Exploration
4,427
13,770
2,150
Depreciation, depletion and amortization
167,432
158,379
308,964
326,270
63,014
126,714
225,870
243,483
General and administrative
17,151
12,300
35,373
23,380
Total operating expenses
330,701
380,816
743,164
767,502
Operating income
22,581
89,446
197,472
215,614
Other income (expenses):
Gain (loss) from derivative financial instruments
44,365
235,847
46,761
(94,492
Other income
259
2,100
522
2,439
Interest expense
(55,042
(55,178
(108,103
(110,015
Total other income (expenses)
(10,418
182,769
(60,820
(202,068
Income before income taxes
12,163
272,215
136,652
13,546
(Provision for) benefit from income taxes
2,837
(141,487
(9,153
1,789
Net income
15,000
130,728
127,499
15,335
Net income attributable to noncontrolling interest
(6,234
(5,886
(11,283
(11,771
Net income available to the Company
8,766
124,842
116,216
3,564
Net income per share:
Basic
0.03
0.45
0.40
0.05
Diluted
0.44
Weighted average shares outstanding:
291,612
290,604
291,465
290,455
294,247
294,026
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
CommonShares
CommonStock-Par Value
AdditionalPaid-inCapital
AccumulatedEarnings
Noncontrolling Interest
Total
Balance at January 1, 2025
292,261
146,130
1,366,274
728,619
92,521
2,333,544
Stock-based compensation
658
330
1,422
1,752
Net income (loss)
(121,278
5,885
(115,393
Contributions from noncontrolling interest
59,500
Distributions to noncontrolling interest
(2,219
Balance at March 31, 2025
292,919
146,460
1,367,696
607,341
155,687
2,277,184
150
75
(2,803
(2,728
Stock issuance costs
(36
5,886
33,000
(3,281
Balance at June 30, 2025
293,069
146,535
1,364,857
732,183
191,292
2,434,867
Balance at January 1, 2026
293,055
641
321
2,910
107,450
5,049
112,499
(8,217
Balance at March 31, 2026
293,696
146,848
1,378,963
1,231,680
312,925
3,070,416
(75
(38
7,096
7,058
6,234
Redemption of noncontrolling interest
(145,000
(300,000
(445,000
Contributions from noncontrolling interest, net of transaction costs
581,654
Deferred tax effect of ownership change in noncontrolling interest
(49,178
(16,372
Balance at June 30, 2026
293,621
CONSOLIDATED STATEMENTS OF CASH FLOWS
CASH FLOWS FROM OPERATING ACTIVITIES:
Adjustments to reconcile net income to net cash provided by operating activities:
9,153
310
(3,400
(Gain) loss on derivative financial instruments
(46,761
94,492
Cash settlements of derivative financial instruments
(37,055
(3,673
Amortization of debt discount and issuance costs
6,200
5,919
15,803
9,971
Decrease in accounts receivable
61,952
1,318
(Increase) decrease in other current assets
(2,949
25,881
Increase in accounts payable and accrued expenses
2,764
46,487
Net cash provided by operating activities
442,170
522,310
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures and acquisitions
(847,738
(642,327
Prepaid drilling costs
18,191
3,060
Proceeds from sales of assets
18,400
Net cash used for investing activities
(811,147
(639,267
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on bank credit facilities
712,000
335,000
Repayments of bank credit facilities
(427,000
(275,000
Debt issuance costs
(1,496
Income tax withholdings on equity awards
(5,514
(10,947
600,126
92,500
(24,589
(5,500
Noncontrolling interest transaction costs
(18,472
Net cash provided by financing activities
390,055
136,017
Net increase in cash and cash equivalents
21,078
19,060
Cash and cash equivalents, beginning of period
6,799
Cash and cash equivalents, end of period
25,859
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2026
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
These unaudited consolidated financial statements include the accounts of Comstock Resources, Inc. and its wholly-owned subsidiaries (collectively, "Comstock" or the "Company"). In management's opinion, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly the financial position of Comstock as of June 30, 2026, and the related results of operations and cash flows for the periods being presented. Net income (loss) and comprehensive income (loss) are the same in all periods presented. All adjustments are of a normal recurring nature unless otherwise disclosed. Certain amounts in prior periods have been reclassified to conform to current period presentation.
The accompanying unaudited consolidated financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States have been omitted pursuant to those rules and regulations, although Comstock believes that the disclosures made are adequate to make the information presented not misleading. These unaudited consolidated financial statements should be read in conjunction with the financial statements and notes thereto included in Comstock's Annual Report on Form 10-K for the year ended December 31, 2025. The results of operations for the period through June 30, 2026 are not necessarily an indication of the results expected for the full year.
Pinnacle Gas Services ("PGS") is a joint venture entity that provides gathering and treating services for natural gas production in the Company's Western Haynesville area. PGS was formed by the Company and an affiliate of Quantum Capital Solutions, Cactus Midstream (II), LLC ("Cactus") in October 2023. On June 15, 2026, PGS redeemed Cactus' interest in PGS for $445 million. The redemption was funded by the issuance of 600,000 Class A-2 Units representing a 27% ownership interest in PGS for $600 million to Starville Evergreen Holdings, LLC ("Starville"), a fund managed by Sixth Street Partners. After certain return hurdles are achieved, Starville's ownership and share of distributable cash reduces to 19.5%. Starville's share of distributable cash is subject to a minimum annualized return and the Class A-2 Units are also entitled to certain exit provisions.
Comstock operates and manages PGS pursuant to a management services agreement and retains the authority to appoint a majority of the directors on the board of directors of PGS. Accordingly, PGS continues to qualify as a variable interest entity to Comstock. Since the Company continues to direct the activities that most significantly impact the performance of PGS and has the obligation to absorb losses or right to receive benefits that could potentially be significant to PGS, Comstock is still considered the primary beneficiary and consolidates the assets, liabilities and results of operations of PGS in the accompanying consolidated financial statements.
Because the Company retained its controlling interest in PGS before and after the redemption of Cactus' interest and issuance of Class A-2 Units, no gain or loss was recognized in the consolidated statements of operations. The carrying amount of the noncontrolling interest attributable to Cactus was retired with the redemption and the difference in the cash consideration paid to Cactus and the carrying value of the redeemed noncontrolling interest was recorded as an adjustment to additional paid-in capital attributable to Comstock. The related change in deferred income taxes to the change in Comstock's ownership of PGS's assets was also recorded to additional paid-in capital. Starville's ownership interest was recognized as noncontrolling interest in the consolidated balance sheet and transaction costs of $18.5 million directly attributable to the issuance of Class A-2 Units were recorded as an adjustment to noncontrolling interest.
PGS assets that cannot be used by Comstock for general corporate purposes include $31.7 million and $8.4 million of cash and $446.8 million and $358.9 million of net other property and equipment as of June 30, 2026 and December 31, 2025, respectively. Other PGS assets that cannot be used by Comstock and PGS liabilities for which creditors do not have recourse to Comstock's assets are not material to the Company's consolidated financial statements. The portions of PGS net income and stockholders' equity not attributable to Comstock's controlling interest are shown separately as noncontrolling interests in the accompanying consolidated statements of operations and statements of stockholders' equity.
Other Current Assets
Other current assets at June 30, 2026 and December 31, 2025 consisted of the following:
34,943
53,134
Prepaid expenses
19,461
5,684
Income tax receivable
3,024
Production tax refunds receivable
2,307
5,827
69
7,588
Property and Equipment
The Company follows the successful efforts method of accounting for its natural gas and oil properties. Costs incurred to acquire natural gas and oil leases and to drill and complete developmental wells are capitalized.
Exploratory well costs are initially capitalized as proved property in the consolidated balance sheets but charged to exploration expense if and when the well is determined not to have found commercial proved natural gas and oil reserves.
The changes in capitalized exploratory well costs are as follows:
Beginning capitalized exploratory well costs
232,390
168,330
210,127
68,223
Additions to exploratory well costs pending the determination of proved reserves
174,359
130,997
349,134
231,104
Determined to have found proved reserves
(137,198
(147,354
(289,710
Ending capitalized exploratory well costs
269,551
151,973
As of June 30, 2026 and December 31, 2025, the Company had no exploratory wells for which costs have been capitalized for a period greater than one year.
The Company periodically assesses the need for an impairment of the capitalized costs for its proved natural gas and oil properties. No impairments were recognized to adjust the carrying value of the Company's proved natural gas and oil properties during any of the periods presented. Unproved natural gas and oil properties are also periodically assessed and any impairment in value is charged to expense. The costs related to unproved properties are transferred to proved natural gas and oil properties and amortized on an equivalent unit-of-production basis when they are reflected in proved natural gas and oil reserves.
The Company determines the fair value of its natural gas and oil properties using a discounted cash flow model and proved and risk-adjusted probable natural gas and oil reserves. Undeveloped acreage can also be valued based on sales transactions in comparable areas. Significant Level 3 assumptions associated with the calculation of discounted future cash flows included in the cash flow model include management's outlook for natural gas and oil prices, production costs, capital expenditures, and future production as well as estimated proved natural gas and oil reserves and risk-adjusted probable natural gas and oil reserves. Management's natural gas and oil price outlook is developed based on third-party longer-term price forecasts as of each measurement date. The expected future net cash flows are discounted using an appropriate discount rate in determining a property's fair value.
It is reasonably possible that the Company's estimates of undiscounted future net cash flows attributable to its natural gas and oil properties may change in the future. The primary factors that may affect estimates of future cash flows include future adjustments, both positive and negative, to proved and appropriate risk-adjusted probable natural gas and oil reserves, results of future drilling activities, future prices for natural gas and oil, and increases or decreases in production and capital costs. As a result of these changes, there may be future impairments in the carrying values of these or other properties.
9
Other property and equipment consists primarily of pipelines and natural gas treating plants ("midstream assets"), computer equipment, furniture and fixtures, office buildings and an airplane which are depreciated over estimated useful lives ranging from three to 50 years on a straight-line basis.
The following table presents the balance of other property and equipment and accumulated depreciation as of June 30, 2026 and December 31, 2025:
(in thousands)
Midstream assets
454,482
363,855
Accumulated depreciation
(7,708
(4,914
Net midstream assets
446,774
358,941
Other property and equipment
22,913
22,801
(2,737
(1,982
Net other property and equipment
20,176
20,819
466,950
379,760
The Company also assesses the need for an impairment of its midstream assets when events or changes in circumstances, such as a significant decline in natural gas volumes gathered and processed, indicate that the Company may not be able to recover its capitalized costs. If impairment is indicated based on undiscounted expected future cash flows attributable to the pipelines and natural gas treating plants, then impairment is recognized to the extent the capitalized costs of the pipelines and natural gas treating plants exceed their estimated fair value. Significant Level 3 assumptions associated with the calculation of discounted future cash flows included in the cash flow model include management's outlook for future natural gas gathering and processing volumes, operation costs and capital expenditures and the expected future net cash flows are discounted at an appropriate rate to determine fair value.
The Company had goodwill of $335.9 million as of June 30, 2026 that was recorded in 2018. The Company is not required to amortize goodwill as a charge to earnings; however, the Company is required to conduct an annual review of goodwill for impairment. The Company performs an annual assessment of goodwill on October 1 of each year and performs interim assessments if indicators of impairment are present. If the carrying value of goodwill exceeds the fair value, an impairment charge would be recorded for the difference between fair value and carrying value. No impairment indicators were identified during the periods presented.
Leases
The Company has right-of-use lease assets of $71.7 million related to its corporate office, certain office equipment, vehicles and drilling rigs with corresponding short-term and long-term liabilities. The value of the lease assets and liabilities are determined based upon discounted future minimum cash flows contained within each of the respective contracts. The Company determines if contracts contain a lease at inception of the contract. To the extent that contract terms representing a lease are identified, leases are identified as being either an operating lease or a finance-type lease. Comstock currently has no finance-type leases. Right-of-use lease assets representing the Company's right to use an underlying asset for the lease term and the related lease liabilities represent the Company's obligation to make lease payments under the terms of the contracts. Short-term leases that have an initial term of one year or less are not capitalized; however, amounts paid for those leases are included as part of its lease cost disclosures. Short-term lease costs exclude expenses related to leases with a lease term of one month or less. Leases for the right to explore for and develop natural gas and oil reserves and the related rights to use the land associated with those leases are reflected as natural gas and oil properties.
Comstock contracts for a variety of equipment used in its natural gas and oil exploration and development activities. Contract terms for this equipment vary broadly, including the contract duration, pricing, scope of services included along with the equipment, cancellation terms, and rights of substitution, among others. The Company's drilling and completion operations routinely change due to changes in commodity prices, demand for natural gas and oil, and the overall operating and economic environment. Accordingly, Comstock manages the terms of its contracts for drilling rigs and completion equipment so as to allow for maximum flexibility in responding to these changing conditions. The Company's hydraulic fracturing fleet contracts are on terms of less than one year and include rights of substitution. The Company has four drilling rig contracts with a three-year term with options to extend the term by mutual agreement at mutually acceptable terms or terminate the contracts at any time without default by the lessor. The terms on the Company's other drilling rig contracts are presently either for periods of one year or less, or they are on terms that provide for cancellation with 30 or 45 days advance notice without a specified expiration date. The costs associated with drilling and completion operations are
10
accounted for under the successful efforts method, which generally require that these costs be capitalized as part of the Company's proved natural gas and oil properties on its balance sheet unless they are incurred on exploration wells that are unsuccessful, in which case they are charged to exploration expense.
Lease costs recognized during the three months and six months ended June 30, 2026 and 2025 were as follows:
Three Months Ended June 30,
Six Months Ended June 30,
Operating lease cost included in general and administrative expense
426
845
851
Operating lease cost included in lease operating expense
574
527
1,179
1,043
Operating lease cost included in natural gas and oil properties
12,147
12,364
24,295
23,664
Variable lease cost (drilling rig costs included in natural gas and oil properties)
3,351
877
15,650
2,598
Short-term lease cost (drilling rig costs included in natural gas and oil properties)
13,244
9,212
25,392
14,599
29,742
23,406
67,361
42,755
Cash payments for operating leases associated with right-of-use lease assets included in net cash provided by operating activities were $1.0 million for both the three months ended June 30, 2026 and 2025, respectively, and $2.0 million and $1.9 million for the six months ended June 30, 2026 and 2025, respectively. Cash payments for operating leases associated with right-of-use lease assets included in net cash used for investing activities were $28.7 million and $22.5 million for the three months ended June 30, 2026 and 2025, respectively, and $65.3 million and $40.9 million for the six months ended June 30, 2026 and 2025, respectively.
As of June 30, 2026 and December 31, 2025, the operating leases had a weighted-average term of 2.1 years and 2.4 years, respectively, and the weighted-average discount rate used to determine the present value of future operating lease payments was 6.7% and 6.8%, respectively. As of June 30, 2026, the Company also had expected future payments for short term leased drilling services of $15.9 million.
As of June 30, 2026, expected future payments related to contracts that contain operating leases were as follows:
July 1 to December 31, 2026
25,078
2027
29,338
2028
14,641
2029
7,488
2030
Total lease payments
76,549
Imputed interest
(5,381
Total lease liability
71,168
Accrued Costs
Accrued costs at June 30, 2026 and December 31, 2025 consisted of the following:
Accrued interest payable
63,404
64,042
Accrued drilling costs
52,326
36,148
Accrued transportation costs
31,155
28,304
Accrued ad valorem and other taxes
12,600
4,000
Accrued employee compensation
5,877
14,926
Accrued lease operating expenses
2,891
3,744
2,934
2,084
11
Reserve for Future Abandonment Costs
Comstock's asset retirement obligations relate to future plugging and abandonment expenses on its natural gas and oil properties and disposal of other facilities. The following table summarizes the changes in Comstock's total estimated liability for such obligations during the periods presented:
Reserve for future abandonment costs at beginning of period
33,996
New wells and facilities placed on production
83
51
Liabilities settled
(29
(34
Accretion expense
603
995
Reserve for future abandonment costs at end of period
35,008
Derivative Financial Instruments and Hedging Activities
All of the Company's derivative financial instruments are used for risk management purposes and, by policy, none are held for trading or speculative purposes. Comstock minimizes credit risk to counterparties of its derivative financial instruments through formal credit policies, monitoring procedures, and diversification. The Company is not required to provide any credit support to its counterparties other than cross collateralization with the assets securing its bank credit facility. None of the Company's derivative financial instruments involve payment or receipt of premiums. The Company classifies the fair value amounts of derivative financial instruments as net current or noncurrent assets or liabilities, whichever the case may be, by commodity contract. None of the Company's derivative contracts were designated as cash flow hedges. All of Comstock's outstanding natural gas derivative financial instruments are tied to the Henry Hub-NYMEX price index.
The Company had the following natural gas price derivative financial instruments at June 30, 2026:
Future Production Period
Six Months EndingDecember 31, 2026
Year EndingDecember 31, 2027
Natural Gas Price Swap Contracts:
Volume (MMBtu)
58,880,000
Average Price per MMBtu
$3.51
$—
Natural Gas Price Collar Contracts:
84,640,000
146,000,000
230,640,000
Average Price per MMBtu:
Average Ceiling
$4.35
$4.44
$4.41
Average Floor
$3.50
The classification of derivative financial instruments of assets or liabilities, consists of the following:
Type
Consolidated Balance Sheet Location
Asset Derivative Financial Instruments:
Natural gas price derivatives
Derivative Financial Instruments – current
Derivative Financial Instruments – long-term
Liability Derivative Financial Instruments:
The Company recognized cash settlements and changes in the fair value of its derivative financial instruments as a single component of other income (expenses).
12
Gains and losses related to cash settlements and changes in the fair value recognized on the Company's derivative contracts recognized in the consolidated statement of operations were as follows:
Gain (loss) on Derivatives Recognized in Earnings
Stock-Based Compensation
Comstock accounts for employee stock-based compensation under the fair value method. Compensation cost is measured at the grant date based on the fair value of the award and is recognized over the award vesting period and included in general and administrative expenses for awards of restricted stock and performance stock units ("PSUs") to the Company's employees and directors. The Company recognized $8.4 million and $5.5 million of stock-based compensation expense within general and administrative expenses related to awards of restricted stock and PSUs to its employees and directors during the three months ended June 30, 2026 and 2025, respectively, and $15.8 million and $10.0 million during the six months ended June 30, 2026 and 2025, respectively.
In January 2026, the Company granted 894,373 shares of restricted stock to its directors and employees, which were valued at $22.47 per share. In June 2026, the Company granted an additional 44,610 shares of restricted stock to its directors, which were valued at $13.45 per share. As of June 30, 2026, Comstock had 1,848,388 shares of unvested restricted stock outstanding at a weighted average grant date fair value of $17.71 per share. Total unrecognized compensation cost related to unvested restricted stock grants of $27.1 million as of June 30, 2026 is expected to be recognized over a period of 2.1 years.
In January 2026, the Company granted 596,623 PSUs to its executive officers, which were valued at $27.85 per unit. As of June 30, 2026, Comstock had 1,831,896 PSUs outstanding with a weighted average grant date fair value of $23.43 per unit. The number of shares of common stock to be issued related to the PSUs is based on the Company's stock price performance as compared to its peers which could result in the issuance of anywhere from zero to 3,663,792 shares of common stock. Total unrecognized compensation cost related to these grants of $28.0 million as of June 30, 2026 is expected to be recognized over a period of 2.1 years.
Segment Reporting
The Company presently operates in one business segment, the exploration and production of North American natural gas and oil, primarily in the Haynesville and Bossier shale. The measure of segment profit or loss used by the chief operating decision maker ("CODM") is consolidated net income, which is provided in the accompanying consolidated statements of operations. The significant segment expenses regularly provided to the CODM are operating expenses and certain significant non-operating items, such as gains or losses from derivative financial instruments, interest expense and income tax expense. These items are also detailed in the accompanying consolidated statements of operations.
Revenue Recognition
Comstock produces natural gas and oil and reports revenues separately for each of these two primary products in its statements of operations. Revenues are recognized upon the transfer of produced volumes to the Company's customers, who take control of the volumes and receive all the benefits of ownership upon delivery at designated sales points.
Gas services revenues represent sales of natural gas purchased for resale from unaffiliated third parties and fees received for gathering and treating services provided by PGS to third parties. Revenues are recognized upon completion of the gathering and treating of contracted natural gas volumes and delivery of purchased natural gas volumes to the Company's customers. Profits and losses earned from the gathering and treating of natural gas produced by the Company's natural gas wells are eliminated in consolidation. Revenues and expenses associated with natural gas purchased for resale are presented on a gross basis in the Company's consolidated statements of operations as the Company acts as the principal in the transaction by assuming the risks and rewards from ownership of the natural gas volumes purchased and the responsibility to deliver the natural gas volumes to their sales point.
All natural gas and oil and gas services revenues are subject to contracts that have commercial substance, contain specific pricing terms, and define the enforceable rights and obligations of both parties. These contracts typically provide for cash settlement within 25 days following each production month and are cancellable upon 30 days' notice by either party for oil and vary for natural gas based upon the terms set out in the confirmations between both parties. Prices for sales of natural gas and oil are generally based upon terms that are common in the oil and gas industry, including index or spot prices, location and quality differentials, as well as market
13
supply and demand conditions. As a result, prices for natural gas and oil routinely fluctuate based on changes in these factors. Prices for gathering and treating services are generally fixed in nature but can vary due to the quality of the gas being treated. Each unit of production (thousand cubic feet of natural gas and barrel of crude oil) represents a separate performance obligation under the Company's contracts since each unit has economic benefit on its own and each is priced separately according to the terms of the contracts.
Comstock has elected to exclude all taxes from the measurement of transaction prices, and its revenues are reported net of royalties and exclude revenue interests owned by others because the Company acts as an agent when selling natural gas and oil on behalf of royalty owners and working interest owners. Revenue is recorded in the month of production based on an estimate of the Company's share of volumes produced and prices realized. Gas services revenue is recorded in the month the services are performed and purchased gas is sold based on an estimate of natural gas volumes and contract prices. The Company recognizes any differences between estimates and actual amounts received in the month when payment is received. Historically, differences between estimated revenues and actual revenues received have not been significant. The amount of natural gas or oil sold may differ from the amount to which the Company is entitled based on its revenue interests in the properties. The Company did not have any significant imbalance positions at June 30, 2026 or December 31, 2025.
The Company recognized accounts receivable of $133.2 million and $203.5 million as of June 30, 2026 and December 31, 2025, respectively, from purchasers for contracts where performance obligations have been satisfied and an unconditional right to consideration exists.
Credit Losses
Substantially all of the Company's accounts receivable are due from either purchasers of natural gas and oil or participants in natural gas and oil wells for which the Company serves as the operator. Generally, operators of natural gas and oil wells have the right to offset future revenues against unpaid charges related to operated wells. Natural gas and oil sales are generally unsecured. Comstock assesses the collectability of its receivables based upon their age, the credit quality of the purchaser or participant and the potential for revenue offset. The Company has not had any significant credit losses in the past and believes its accounts receivable are fully collectible. Accordingly, no allowance for doubtful accounts has been recorded for the six months ended June 30, 2026 and 2025.
Income Taxes
Deferred income taxes are provided to reflect the future tax consequences or benefits of differences between the tax basis of assets and liabilities and their reported amounts in the financial statements using enacted tax rates.
In recording deferred income tax assets, the Company considers whether it is more likely than not that its deferred income tax assets will be realized in the future. The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income during the periods in which those deferred income tax assets would be deductible. The Company believes that after considering all the available objective evidence, historical and prospective, with greater weight given to historical evidence, management is not able to determine that it is more likely than not that all of its deferred tax assets will be realized. As a result, the Company established valuation allowances for its deferred tax assets and U.S. federal and state net operating loss carryforwards that are not expected to be utilized due to the uncertainty of generating taxable income prior to the expiration of the carryforward periods. The Company will continue to assess the valuation allowances against deferred tax assets considering all available information obtained in future periods.
The following is an analysis of the consolidated income tax provision (benefit):
Current - Federal
(1,710
Current - State
36
Deferred - Federal
(742
66,010
18,082
80
Deferred - State
(2,095
77,151
(8,929
(195
(2,837
141,487
(1,789
14
The difference between the federal statutory rate of 21% and the effective tax rate is due to the following:
Tax at statutory rate
21.0
%
Tax effect of:
Research and development and other income tax credits
(20.8
(1.0
(5.9
(20.3
State income taxes, net of federal benefit
(23.8
28.4
(5.3
(1.2
Valuation allowance on deferred tax assets
(3.1
0.8
(9.1
10.4
(2.1
(3.4
Nondeductible stock-based compensation
9.3
(6.6
2.1
(7.0
0.1
(0.2
Effective tax rate
(23.3
)%
52.0
6.7
(13.2
For the three and six months ended June 30, 2026, the effective rate differed from the statutory rate due primarily to the impact of federal research and development credits, release of federal valuation allowance and state income taxes resulting from state tax credits. The Company's federal income tax returns for the years subsequent to December 31, 2021 remain subject to examination, with the Company's 2022 and 2023 federal income tax returns currently under examination with the United States Internal Revenue Service. The Company's income tax returns in major state income tax jurisdictions remain subject to examination for various periods subsequent to December 31, 2022. The Company believes that its significant filing positions and deductions will be sustained under audit or the final resolution will not have a material effect on the consolidated financial statements. Therefore, the Company has not established any significant reserves for uncertain tax positions.
Fair Value Measurements
The Company holds or has held certain financial assets and liabilities that are required to be measured at fair value. These include cash and cash equivalents held in bank accounts and derivative financial instruments. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. A three-level hierarchy is followed for disclosure to show the extent and level of judgment used to estimate fair value measurements:
Level 1 — Inputs used to measure fair value are unadjusted quoted prices that are available in active markets for the identical assets or liabilities as of the reporting date.
Level 2 — Inputs used to measure fair value, other than quoted prices included in Level 1, are either directly or indirectly observable as of the reporting date through correlation with market data, including quoted prices for similar assets and liabilities in active markets and quoted prices in markets that are not active. Level 2 also includes assets and liabilities that are valued using models or other pricing methodologies that do not require significant judgment since the input assumptions used in the models, such as interest rates and volatility factors, are corroborated by readily observable data from actively quoted markets for substantially the full term of the financial instrument.
Level 3 — Inputs used to measure fair value are unobservable inputs that are supported by little or no market activity and reflect the use of significant management judgment. These values are generally determined using pricing models for which the assumptions utilize management's estimates of market participant assumptions.
15
Fair Values – Reported
The following presents the carrying amounts and the fair values of the Company's financial instruments as of June 30, 2026 and December 31, 2025:
December 31, 2025
Carrying Value
Fair Value
Assets:
Commodity-based derivatives (1)
75,386
Liabilities:
Bank credit facilities (2)
545,000
260,000
6.75% senior notes due 2029 (3)
1,610,099
1,592,962
1,607,880
1,603,582
5.875% senior notes due 2030 (3)
965,000
904,688
931,225
Earnings Per Share
Unvested restricted stock containing non-forfeitable rights to dividends are included in common stock outstanding and are considered to be participating securities and included in the computation of basic and diluted earnings per share pursuant to the two-class method. At June 30, 2026 and December 31, 2025, 1,848,388 and 1,957,381 shares of restricted stock, respectively, are included in common stock outstanding as such shares have a non-forfeitable right to participate in any dividends that might be declared and have the right to vote on matters submitted to the Company's stockholders.
Weighted average shares of unvested restricted stock outstanding were as follows:
Unvested restricted stock
2,057
2,342
2,151
2,330
PSUs represent the right to receive a number of shares of the Company's common stock that may range from zero to up to two times the number of PSUs granted on the award date based on the achievement of certain performance measures during a performance period. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, which would be issuable at the end of the respective period, assuming that date was the end of the performance period. The treasury stock method is used to measure the dilutive effect of PSUs.
Weighted average unearned PSUs outstanding were as follows:
(In thousands, except per unit amounts)
Weighted average PSUs
2,099
1,411
2,064
1,351
Weighted average grant date fair value per unit
$23.43
$19.46
For the three and six months ended June 30, 2026, the weighted average shares of unvested restricted stock and PSUs were excluded from the computation of earnings per share because to include them would have been antidilutive to the calculation.
16
Basic and diluted income per share for the three months and six months ended June 30, 2026 and 2025 were determined as follows:
Income
Shares
Per Share
Income allocable to unvested restricted stock
(61
(1,045
Basic income available to the Company
8,705
129,683
Effect of Dilutive Securities:
Restricted stock
1,045
1,364
Performance stock units
2,279
Diluted income available to the Company
(852
(122
115,364
15,213
122
1,350
2,221
Supplementary Information with Respect to the Consolidated Statements of Cash Flows
Cash payments made for interest and income taxes and other non-cash investing activities for the six months ended June 30, 2026 and 2025, respectively, were as follows:
Cash payments for:
Interest payments
102,541
104,733
Income tax payments (refunds)
(31,000
Non-cash investing activities include:
Increase (decrease) in accrued capital expenditures
16,178
(2,575
Liabilities assumed in exchange for right-of-use lease assets
453
36,244
Recent Accounting Pronouncements
In November 2024, the FASB issued ASU 2024-03 "Disaggregation of Income Statement Expenses". ASU 2024-03 requires additional disclosure, in the notes to the financial statements, of specified information about certain costs and expenses, including purchases of inventory, employee compensation, depreciation, intangible asset amortization and depreciation, depletion and amortization recognized as part of oil and gas-producing activities included in each relevant expense caption. ASU 2024-03 is effective for annual reporting periods beginning after December 15, 2026 and interim reporting periods beginning after December 15, 2027 and will not have an impact on the Company's reported results of operations, financial position or liquidity. The Company is still evaluating the impact of this standard on its financial statement disclosures.
17
(2) LONG-TERM DEBT
At June 30, 2026, long-term debt was comprised of the following:
6.75% Senior Notes due 2029:
Principal
1,623,880
Discount, net of amortization
(13,781
5.875% Senior Notes due 2030:
Bank Credit Facilities:
Comstock Principal
PGS Principal
Debt issuance costs, net of amortization
(21,329
Comstock Bank Credit Facility
As of June 30, 2026, Comstock had $545.0 million outstanding under its bank credit facility. Aggregate commitments under the bank credit facility are $1.5 billion, which matures on November 15, 2027. Borrowings under the bank credit facility are subject to a borrowing base that is currently set at $2.0 billion. The borrowing base is re-determined on a semi-annual basis and upon the occurrence of certain other events. Borrowings under the bank credit facility are secured by substantially all of the assets of the Company and its subsidiaries, except for PGS, and bear interest at the Company's option, at either adjusted Secured Overnight Financing Rate ("SOFR") plus 2.25% to 3.25% or an alternate base rate plus 1.25% to 2.25%, in each case depending on the utilization of the borrowing base. The Company also pays a commitment fee of 0.375% to 0.5%, which is dependent on the utilization of the borrowing base. The bank credit facility places certain restrictions upon the Company's and its restricted subsidiaries' ability to, among other things, incur additional indebtedness, pay cash dividends, repurchase common stock, make certain loans, investments and divestitures and redeem the senior notes. The only financial covenants are the maintenance of a leverage ratio of less than 3.5 to 1.0 and an adjusted current ratio of at least 1.0 to 1.0. The Company was in compliance with the covenants as of June 30, 2026.
PGS Bank Credit Facility
As of June 30, 2026, PGS had no borrowings outstanding under its bank credit facility. Aggregate commitments under the bank credit facility are $150 million, which matures on March 26, 2030. Borrowings under the bank credit facility bear interest at PGS's option, at either SOFR plus 2.5% to 3.5% or an alternate base rate plus 1.5% to 2.5%, in each case depending on a consolidated net leverage ratio. PGS also pays a commitment fee of 0.375% to 0.5%, which is dependent on the PGS consolidated net leverage ratio. This bank credit facility contains financial covenants for PGS that require the maintenance of an interest coverage ratio of at least 2.5 to 1.0 and a consolidated net leverage ratio of less than 4.0 to 1.0. PGS was in compliance with the covenants as of June 30, 2026.
(3) COMMITMENTS AND CONTINGENCIES
In October 2025, the Company entered into an agreement for one new drilling rig, with a pad to pad contract term. Comstock took delivery of this rig in January 2026. Remaining commitments for drilling rigs on pad to pad agreements total $15.9 million as of June 30, 2026.
From time to time, the Company is involved in certain litigation that arises in the normal course of its operations. The Company records a loss contingency for these matters when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. The Company does not believe the resolution of these matters will have a material effect on the Company's financial position, results of operations or cash flows and no material amounts are accrued relative to these matters at June 30, 2026 or 2025.
18
(4) RELATED PARTY TRANSACTIONS
Comstock operates natural gas and oil properties held by partnerships owned by its majority stockholder. The Company charges the partnerships for the costs incurred to drill, complete and produce wells, as well as drilling and operating overhead fees. Comstock also provides natural gas marketing services to the partnerships, including evaluating potential markets and providing hedging services, in return for a fee equal to $0.02 per Mcf for natural gas marketed. The Company received $236 thousand and $260 thousand for the three months ended June 30, 2026 and 2025, respectively, and $475 thousand and $599 thousand for the six months ended June 30, 2026 and 2025, respectively, for drilling, operating and marketing services provided to the partnerships. The fees received for the services are reflected as a reduction of general and administrative expenses in the accompanying consolidated statements of operations.
In connection with the operation of the wells, the Company had a $3.2 million and $3.6 million receivable from the partnerships at June 30, 2026 and December 31, 2025, respectively.
19
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
This report contains forward-looking statements that involve risks, uncertainties and assumptions that are made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 including those described under the heading "Risk Factors" in our Annual Report on Form 10-K for the year ended December 31, 2025 (the "Annual Report"). All statements other than statements of historic facts contained, or incorporated by reference, in this report, may be forward-looking statements. Actual results may differ materially from those anticipated in our forward-looking statements due to many factors. Such forward-looking statements are based on management's current expectations and are subject to a number of factors and uncertainties which could cause actual results to differ materially from those described herein. Although we believe the expectations in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. You are cautioned not to place undue reliance on the forward-looking statements included in this report, which speak only as of the date made. We expressly disclaim any obligation or undertaking to release publicly any updates or revisions to any forward-looking statement to reflect any change in our expectations with regard thereto or any change of events, conditions or circumstances on which any such statement was based, except as required by law. The following discussion should be read in conjunction with the consolidated financial statements and notes thereto included in this report and in our Annual Report as well as with the Risk Factors contained in our Annual Report.
Results of Operations
Net Production Data:
Natural gas (MMcf)
113,069
112,164
210,924
227,193
Oil (MBbls)
23
Natural gas equivalent (MMcfe)
113,102
112,238
211,021
227,329
Expenses:
Average Sales Price:
Natural gas (per Mcf)
2.54
3.02
3.35
3.31
Oil (per Bbl)
95.20
57.00
77.13
62.74
Average equivalent (Mcfe)
2.55
3.03
Expenses ($ per Mcfe):
0.06
0.09
0.10
0.38
0.37
0.25
0.28
0.27
0.29
Gas Services:
Gas services revenue
Gas services expense
Revenues –
Natural gas and oil sales of $288.2 million for the three months ended June 30, 2026 decreased by $51.7 million (15%) as compared to $340.0 million for the second quarter of 2025. The decrease was due to lower natural gas prices realized in the second quarter of 2026 as compared to the same period in 2025. The average realized price for our natural gas was $2.54 per thousand cubic feet ("Mcf"), which decreased 16% from the average realized natural gas price in the second quarter of 2025. Our natural gas production for the second quarter of 2026 increased 1% to 113.1 billion cubic feet ("Bcf") (1.2 Bcf per day). Natural gas production for the second quarter of 2025 was 112.2 Bcf (1.2 Bcf per day) and was sold at an average price of $3.02 per Mcf.
Natural gas and oil sales of $707.3 million for the six months ended June 30, 2026 decreased by $45.7 million (6%) as compared to $753.0 million for the six months ended June 30, 2025, which was primarily attributable to lower natural gas production, which decreased 7% to 210.9 Bcf (1.2 Bcf per day) during the first six months of 2026. Natural gas prices increased by 1% during the first six months of 2026 as compared to 2025 natural gas prices. Our natural gas production for the first six months of 2025 was 227.2 Bcf (1.3 Bcf per day) and was sold at an average price of $3.31 per Mcf.
We utilize natural gas price derivative financial instruments to manage our exposure to changes in prices of natural gas and to protect returns on investment from our drilling activities. The following table presents our natural gas prices before and after the effect of cash settlements of our derivative financial instruments:
Average Realized Natural Gas Price:
Natural gas, per Mcf
Cash settlements on derivative financial instruments, per Mcf
0.39
0.04
(0.18
(0.02
Price per Mcf, including cash settlements on derivative financial instruments
2.93
3.06
3.17
3.29
Gas service revenues of $63.5 million decreased $66.8 million (51%) for the second quarter of 2026 from $130.3 million in the second quarter of 2025. Gas service revenues of $230.0 million decreased $0.2 million for the first six months of 2025 from $230.2 million for the first six months of 2025. The decreases were primarily due to lower natural gas prices related to sales of natural gas purchased to utilize our excess transport capacity.
Costs and Expenses –
Our production and ad valorem taxes decreased $3.4 million (32%) to $7.2 million for the second quarter of 2026 from $10.6 million in the second quarter of 2025. Production and ad valorem taxes decreased $4.1 million (19%) to $17.6 million during the first six months of 2026 from $21.7 million during the first six months of 2025. The decreases were due primarily to the sale of producing properties in the prior periods and changes in natural gas prices.
Gathering and transportation costs for the second quarter of 2026 increased $1.6 million (4%) to $43.3 million as compared to $41.8 million in the second quarter of 2025. Gathering and transportation costs during the first six months of 2026 increased $0.8 million (1%) to $85.1 million as compared to the first six months of 2025. The increases in both periods were due primarily to production growth in areas with higher average gathering and transportation rates.
Our lease operating expense of $28.2 million ($0.25 per Mcfe) for the second quarter of 2026 decreased $3.0 million (10%) as compared to our lease operating expense of $31.1 million ($0.28 per Mcfe) for the second quarter of 2025. Lease operating expense of $56.4 million ($0.27 per Mcfe) during the first six months of 2026 decreased $9.7 million (15%) from lease operating expense of $66.1 million ($0.29 per Mcfe) during the first six months of 2025. The decreases were due primarily to the sale of producing properties in the prior periods.
Gas service expenses of $63.0 million decreased $63.7 million (50%) for the second quarter of 2026 from $126.7 million in the second quarter of 2025. Gas service expenses of $225.9 million decreased $17.6 million (7%) for the first six months of 2026 from $243.5 million for the first six months of 2025. The decreases were primarily due to lower natural gas prices and volumes related to purchases of third party natural gas for resale.
Depreciation, depletion and amortization ("DD&A") increased $9.1 million to $167.4 million in the second quarter of 2026 from $158.4 million in the second quarter of 2025. Our DD&A per equivalent Mcf produced was $1.48 per Mcfe for the quarter ended June 30, 2026 as compared to $1.41 per Mcfe for the quarter ended June 30, 2025. The increase was due primarily to higher finding and development costs in 2026. DD&A decreased $17.3 million to $309.0 million for the first six months of 2026 from $326.3 million during the first six months of 2025. Our DD&A per equivalent Mcf produced was $1.46 per Mcfe for the six months ended June 30, 2026, which was comparable to $1.44 per Mcfe for the six months ended June 30, 2025.
21
General and administrative expenses, which are reported net of overhead reimbursements, increased to $17.2 million for the second quarter of 2026 as compared to $12.3 million in the second quarter of 2025. General and administrative expenses increased to $35.4 million for the six months ended June 30, 2026 as compared to $23.4 million for the six months ended June 30, 2025. The increases in both periods were primarily due to higher stock-based compensation, which increased to $8.4 million in the second quarter of 2026 as compared to $5.5 million in the second quarter of 2025, and a reduction in overhead reimbursements resulting from the property divestitures completed in 2025. For the six months ended June 30, 2026, stock-based compensation increased to $15.8 million as compared to $10.0 million for the same period in 2025.
We use derivative financial instruments as part of our price risk management program to protect our capital investments. During the quarter ended June 30, 2026, we had net gains related to our derivative financial instruments of $44.4 million, as compared to net gains on derivative financial instruments of $235.8 million during the quarter ended June 30, 2025, resulting from the decrease in future natural gas prices since June 30, 2025. Realized net gains from our price risk management program were $43.3 million for the quarter ended June 30, 2026 as compared to realized net gains of $4.3 million for the quarter ended June 30, 2025. Net gains on derivative financial instruments were $46.8 million for the first six months of 2026 as compared to net losses of $94.5 million for the first six months of 2025, resulting from a decrease in future natural gas prices since December 31, 2025. Realized net losses from our price risk management program were $37.1 million for the first six months of 2026 as compared to realized net losses of $3.7 million for the first six months of 2025.
Interest expense was $55.0 million and $55.2 million for the quarters ended June 30, 2026 and 2025, respectively, and $108.1 million and $110.0 million for six months ended June 30, 2026 and 2025, respectively. The decrease in interest expense was due primarily to decreased borrowings on our bank credit facility.
Exploration expense was $4.4 million for the second quarter of 2026, and exploration expense was $13.8 million and $2.2 million for the six months ended June 30, 2026 and 2025, respectively, which were related to the acquisition of seismic data in our Western Haynesville area.
Income taxes for the quarters ended June 30, 2026 and 2025 were a benefit of $2.8 million and a provision of $141.5 million, respectively. Income taxes for the six months ended June 30, 2026 and 2025 were a provision of $9.2 million and a benefit of $1.8 million, respectively. Income taxes for the quarters ended June 30, 2026 and 2025 reflect an effective tax rate of (23.3)% and 52.0%, respectively, and income taxes for the six months ended June 30, 2026 and 2025 reflect an effective tax rate of 6.7% and (13.2)%, respectively. The difference between the federal statutory tax rate of 21% and our effective rate is primarily attributable to research and development and other tax credits, release of valuation allowance on deferred tax assets, state income taxes, changes in certain nondeductible items and the income attributable to noncontrolling interest.
We reported net income available to the Company of $8.8 million for the quarter ended June 30, 2026 as compared to net income available to the Company of $124.8 million for the quarter ended June 30, 2025. Income from operations for the second quarter of 2026 was $22.6 million as compared to income from operations of $89.4 million for the second quarter of 2025. In the first six months of 2026, we reported net income available to the Company of $116.2 million as compared to net income available to the Company of $3.6 million for the first six months of 2025. Income from operations for the first six months of 2026 was $197.5 million as compared to income from operations of $215.6 million for the first six months of 2025.
22
Cash Flows, Liquidity and Capital Resources
Cash Flows
The following table summarizes sources and uses of cash and cash equivalents:
Sources of cash and cash equivalents:
Operating activities
Borrowings on bank credit facilities, net of repayments
285,000
60,000
Proceeds from asset sales
1,327,224
674,810
Uses of cash and cash equivalents:
Capital expenditures
829,547
639,267
445,000
24,589
5,500
7,010
10,983
1,306,146
655,750
Cash flows from operating activities. Net cash provided by our operating activities decreased $80.1 million (15%) to $442.2 million in the first six months of 2026 from $522.3 million in the same period in 2025. The decrease was due primarily to lower natural gas production and lower realized natural gas prices.
Contributions and redemption of noncontrolling interest. On June 15, 2026, PGS redeemed Cactus' interest in PGS for $445 million. The redemption was funded by the issuance of 600,000 Class A-2 Units representing a 27% ownership interest in PGS for $600 million to Starville, net of $18.5 million in related transaction costs.
Capital expenditures. Our capital expenditures are summarized in the following table:
Acquisitions:
Unproved property
39,449
19,616
Exploration and development:
Development leasehold costs
7,374
8,851
Exploratory drilling and completion costs
Development drilling and completion costs
357,915
269,569
Other development costs
19,277
8,434
Asset retirement obligations
Total exploration and development
773,232
537,591
Midstream property and equipment
90,627
102,940
112
(762
Total capital expenditures
863,971
639,769
Change in accrued capital expenditures and other
(16,179
2,575
(18,191
(3,060
Change in asset retirement obligations
(54
(17
Total cash capital expenditures
We drilled 34 (30.9 net) wells and completed 29 (24.4 net) Haynesville and Bossier shale operated wells during the first six months of 2026. We currently expect to spend an additional $720 million to $820 million in the remaining six months of 2026 on drilling, completion, infrastructure and other activity.
Liquidity and Capital Resources
As of June 30, 2026, we had $1.2 billion of liquidity, comprised of $1.1 billion of unused borrowing capacity under our bank credit facilities and $45.0 million of cash and cash equivalents on hand. $150 million of unused borrowing capacity under our PGS bank credit facility is restricted to PGS midstream activities. Our short and long-term capital requirements consist primarily of funding our development, exploration and midstream activities, acquisitions, payments of contractual obligations and debt service.
We expect to fund our future development and exploration activities with future operating cash flow and borrowings under our bank credit facilities. The timing of most of our future capital expenditures is discretionary because of our limited number of material long-term capital expenditure commitments. Consequently, we have a significant degree of flexibility to adjust the level of our capital expenditures as circumstances warrant. We believe that our cash provided by operations and borrowings available under our bank credit facilities will be sufficient to satisfy our foreseeable liquidity needs and capital expenditure requirements for at least the next twelve months. If our plans or assumptions change or our assumptions prove to be inaccurate, we may be required to seek additional capital, including debt or equity financing. We cannot provide any assurance that we will be able to obtain such capital, or if such capital is available, that we will be able to obtain it on acceptable terms.
We do not have a specific acquisition budget for the remainder of 2026 because the timing and size of acquisitions are unpredictable. We intend to use our cash flows from operations, borrowings under our bank credit facilities, or other debt or equity financing to the extent available, to finance such acquisitions. The availability and attractiveness of these sources of financing will depend upon a number of factors, some of which will relate to our financial condition and performance and some of which will be beyond our control, such as prevailing interest rates, natural gas and oil prices and other market conditions. Lack of access to the debt or equity markets due to general economic conditions could impede our ability to complete acquisitions.
As of June 30, 2026, we had $545.0 million outstanding under the Comstock bank credit facility. Aggregate commitments under this bank credit facility are $1.5 billion, which matures on November 15, 2027. Borrowings under our bank credit facility are subject to a borrowing base that is currently set at $2.0 billion. The borrowing base is re-determined on a semi-annual basis and upon the occurrence of certain other events. Borrowings under the Comstock bank credit facility are secured by substantially all of our assets and those of our subsidiaries, except for PGS, and bear interest at our option at either adjusted SOFR plus 2.25% to 3.25% or an alternate base rate plus 1.25% to 2.25%, in each case depending on the utilization of the borrowing base. We also pay a commitment fee of 0.375% to 0.5%, which is dependent on the utilization of the borrowing base. Comstock's bank credit facility places certain restrictions upon our and our restricted subsidiaries' ability to, among other things, incur additional indebtedness, pay cash dividends, repurchase common stock, make certain loans, investments and divestitures and redeem the senior notes. The only financial covenants are the maintenance of a leverage ratio of less than 3.5 to 1.0, and an adjusted current ratio of at least 1.0 to 1.0. We were in compliance with the covenants as of June 30, 2026.
As of June 30, 2026, PGS had no borrowings outstanding under its bank credit facility. Aggregate commitments under the PGS bank credit facility are $150 million, which matures on March 26, 2030. Borrowings under the PGS bank credit facility bear interest at our option, at either SOFR plus 2.5% to 3.5% or an alternate base rate plus 1.5% to 2.5%, in each case depending on a consolidated net leverage ratio. PGS also pays a commitment fee of 0.375% to 0.5%, which is dependent on the PGS consolidated net leverage ratio. The PGS bank credit facility contains financial covenants that require the maintenance of an interest coverage ratio of at least 2.5 to 1.0 and a consolidated net leverage ratio of less than 4.0 to 1.0. PGS was in compliance with the covenants as of June 30, 2026.
Federal and State Taxation
At June 30, 2026, we had $1.5 billion in U.S. federal net operating loss ("NOL") carryforwards and $2.0 billion in certain state NOL carryforwards. As a result of the change of control in August 2018, our ability to use NOLs to reduce taxable income is limited. If we do not generate a sufficient level of taxable income prior to the expiration of the pre-2018 NOL carryforward periods, then we will lose the ability to apply those NOLs as offsets to future taxable income. We estimate that $720.7 million of the U.S. federal NOL carryforwards and $1.2 billion of the estimated state NOL carryforwards will expire unused.
Our federal income tax returns for the years subsequent to December 31, 2021 remain subject to examination. Our income tax returns in major state income tax jurisdictions remain subject to examination for various periods subsequent to December 31, 2022. Currently, we are under examination with the United States Internal Revenue Service and believe that our significant filing positions and deductions will be sustained under audit or the final resolution will not have a material effect on the consolidated financial statements. Therefore, we have not established any significant reserves for uncertain tax positions.
Critical Accounting Policies and Estimates
Our management’s discussion and analysis of our financial condition and results of operations are based on our condensed consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United
24
States ("GAAP"). The preparation of these financial statements requires us to make estimates and judgments that affect the reported amount of assets, liabilities, and expenses and the disclosure of contingent assets and liabilities as of the date of the financial statements. On an ongoing basis, we evaluate our estimates and judgments. We base our estimates on historical experience, known trends and events, and various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying value of assets and liabilities that are not readily apparent from other sources. Actual results may differ materially from these estimates under different assumptions or conditions.
In Part II, Item 7 of the Annual Report, we disclosed our critical accounting policies and estimates, which are made in accordance with GAAP, involve a significant level of estimation uncertainty and have had or are reasonably likely to have a material impact on our financial condition or results of operation. There have been no significant changes to our critical accounting policies and estimates during the six months ended June 30, 2026, as compared to those disclosed in the Annual Report.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
Natural Gas and Oil Prices
Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of natural gas and oil. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors, some of which are beyond our control. Factors influencing natural gas and oil prices include the level of global demand for oil, the foreign supply of natural gas and oil, the effect of the wars in Iran and Ukraine, the establishment of and compliance with production quotas by oil exporting countries, weather conditions that determine the demand for natural gas, the price and availability of alternative fuels and overall economic conditions. It is impossible to predict future natural gas and oil prices with any degree of certainty. Sustained weakness in natural gas and oil prices may adversely affect our financial condition and results of operations and may also reduce the amount of natural gas and oil reserves that we can produce economically. Any reduction in our natural gas and oil reserves, including reductions due to price fluctuations, can have an adverse effect on our ability to obtain capital for our exploration and development activities. Similarly, any improvements in natural gas and oil prices can have a favorable impact on our financial condition, results of operations and capital resources.
As of June 30, 2026, we had natural gas price swaps to hedge approximately 58.9 Bcf of our 2026 natural gas production at an average price of $3.51 per MMBtu. We also had natural gas collars to hedge approximately 84.6 Bcf of our 2026 natural gas production at an average ceiling price of $4.35 and an average floor price of $3.50 and 146.0 Bcf of our 2027 natural gas production at an average ceiling price of $4.44 and an average floor price of $3.50. None of our derivative contracts have margin requirements or collateral provisions that could require funding prior to the scheduled cash settlement date.
An increase of 10% in the market price of natural gas on June 30, 2026 would decrease the fair value of our natural gas price swaps and collars by approximately $61.5 million. A decrease of 10% in the market price of natural gas on June 30, 2026 would increase the fair value of our natural gas price swaps and collars by approximately $63.7 million. The impact of hypothetical changes in market prices of natural gas on our natural gas derivative financial instruments does not include the offsetting impact that the same hypothetical changes in market prices of natural gas may have on our physical sales of natural gas. Since our outstanding natural gas derivative financial instruments hedge only a portion of our forecasted physical gas production, a positive or negative impact to the fair value of our natural gas derivative financial instruments would be partially offset by our physical sales of natural gas.
Interest Rates
At June 30, 2026, we had approximately $3.1 billion principal amount of long-term debt outstanding. $965.0 million of our long-term debt bear interest at a fixed rate of 5.875% and $1.62 billion of our long-term debt bear interest at a fixed rate of 6.75%. As of June 30, 2026, the fair market value of the 5.875% senior notes due in 2030 and the 6.75% senior notes due in 2029 was $904.7 million and $1.59 billion, respectively, based on the market price of approximately 94% and 98%, respectively, of the face amount of such debt. At June 30, 2026, we had $545.0 million outstanding under our bank credit facilities, which are subject to variable rates of interest that are tied to SOFR or the corporate base rate, at our option. Any increase in these interest rates would have an adverse impact on our results of operations and cash flow.
ITEM 4. CONTROLS AND PROCEDURES
As of June 30, 2026, we carried out an evaluation, under the supervision and with the participation of our chief executive officer and chief financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934). Based on this evaluation, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures were effective as of June 30, 2026 to provide reasonable assurance that information required to be disclosed by us in the reports filed or submitted by us under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and to provide reasonable assurance that information required to be disclosed by us is accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating our disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. There were no changes in our internal controls over financial reporting (as such term is defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) that occurred during the three months ended June 30, 2026 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.
PART II — OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
From time to time, we are involved in certain litigation that arises in the normal course of our operations. We record a loss contingency for these matters when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. We do not believe the resolution of these matters will have a material effect on our financial position, results of operations or cash flows and no material amounts are accrued relative to these matters at June 30, 2026 or 2025.
ITEM 1A. RISK FACTORS
We are subject to various risks and uncertainties in the course of our business. For a discussion of such risks and uncertainties, please see "Item 1A. Risk Factors" in the Annual Report. There have been no material changes to the Risk Factors we have disclosed in the Annual Report.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
None.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
ITEM 5. OTHER INFORMATION
During the three months ended June 30, 2026, none of our directors or officers adopted, modified or terminated a "Rule 10b5-1 trading arrangement" or "non-Rule 10b5-1 trading arrangement," as those terms are defined in Regulation S-K, Item 408(a).
ITEM 6. EXHIBITS
Exhibit No.
Description
3.1
Second Amended and Restated Articles of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K dated August 13, 2018).
3.2
Amendment to Second Amended and Restated Articles of Incorporation of the Company dated July 16, 2019 (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K dated July 15, 2019).
3.3
Amended and Restated Bylaws (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K dated August 21, 2014).
3.4
First Amendment to Amended and Restated Bylaws of the Company (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K dated August 17, 2018).
3.5
Amendment No. 2 to the Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 to our Current Report on Form 8-K dated July 15, 2019).
10.1*
Fourth Amendment to Second Amended and Restated Credit Agreement dated as of June 15, 2026, among the Company, the lenders party thereto and Wells Fargo Bank National Association as Administrative Agent.
31.1*
Section 302 Certification of the Chief Executive Officer.
31.2*
Section 302 Certification of the Chief Financial Officer.
32.1†
Certification for the Chief Executive Officer as required by Section 906 of the Sarbanes-Oxley Act of 2002.
32.2†
Certification for the Chief Financial Officer as required by Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*
Inline XBRL Instance Document
101.SCH*
Inline XBRL Taxonomy Extension Schema with Embedded Linkbase Documents
104*
Cover Page Interactive Data File (embedded within the Inline XBRL document)
_____________________________
* Filed herewith.
† Furnished herewith.
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Date: July 30, 2026
/s/ M. JAY ALLISON
M. Jay Allison, Chairman and Chief Executive Officer
(Principal Executive Officer, Duly Authorized Officer)
/s/ ROLAND O. BURNS
Roland O. Burns, President, Chief Financial Officer and Secretary
(Principal Financial and Accounting Officer)