Diversified Energy (NYSE: DEC) swings to H1 2026 profit after asset deals
Diversified Energy Company reported higher revenue and a return to profitability for the six months ended June 30, 2026. Total revenue was $ 839,052 (in thousands) versus $ 649,212 (in thousands) a year earlier, and net income attributable to DEC was $ 86,332 (in thousands) compared with a net loss of $ ( 25,460 ) (in thousands). Net cash provided by operating activities rose to $ 257,516 (in thousands).
During 2026 the company acquired Sheridan assets for cash consideration of $ 236,387 (in thousands) and completed several non-core divestitures, including Barnett assets for $ 116 million and undeveloped acreage for $ 126 million, generating gains on property sales. Capital structure remained debt-heavy, with total borrowings of $ 2,978,729 and interest expense of $ 124,723 (in thousands) for the six-month period; the Credit Facility borrowing base increased to $ 900 million with $ 669 million available. Subsequent to quarter-end, Diversified agreed to acquire Camino-related properties for a gross purchase price of approximately $1.2 billion and the board declared a $0.29 per share cash dividend payable December 31, 2026.
Positive
- Diversified returned to profitability for the six months ended June 30, 2026, with net income attributable to DEC of $ 86,332 (in thousands) versus a prior-year loss, and generated $ 257,516 (in thousands) of net cash from operating activities.
Negative
- None.
Key Figures
Total Revenue: $ 839,052 (in thousands)
Net Income Attributable to DEC: $ 86,332 (in thousands)
Net Cash from Operating Activities: $ 257,516 (in thousands)
+5 more
8 metrics
Total Revenue
$ 839,052 (in thousands)
Six months ended June 30, 2026 total revenue.
Net Income Attributable to DEC
$ 86,332 (in thousands)
Six months ended June 30, 2026 net income attributable to DEC.
Net Cash from Operating Activities
$ 257,516 (in thousands)
Net cash provided by operating activities for six months ended June 30, 2026.
Total Borrowings
$ 2,978,729
Total borrowings outstanding as of June 30, 2026.
Stockholders' Equity Attributable to DEC
$ 950,691
Stockholders' equity attributable to DEC as of June 30, 2026.
Sheridan Acquisition Consideration
$ 236,387
Cash consideration paid for Sheridan asset acquisition on April 30, 2026.
ABS XII Notes Principal
$ 850,000
Total principal amount of ABS XII Notes issued in May 2026.
Camino Acquisition Price
approximately $1.2 billion
Gross purchase price for Camino-related properties announced July 2, 2026.
Key Terms
asset-backed securities, marginal well tax credit, asset retirement obligations, Monte Carlo simulation, +1 more
5 terms
asset-backed securities financial
"to issue asset-backed securities with a total principal amount of $850 million"
A type of investment created by pooling many similar cash‑flowing assets — like mortgages, car loans, or credit card receivables — and selling slices of that bundle to investors who then receive the payments those assets generate. Think of it as a fruit basket where buyers earn the fruit sales: investors get steady income but also take on the risk that the underlying loans stop performing or are paid off early. Investors care because these securities can provide predictable yield, portfolio diversification, and varying levels of credit and liquidity risk depending on the quality of the underlying assets.
marginal well tax credit financial
"primarily due to the impact of federal tax credits, principally the marginal well tax credit"
asset retirement obligations financial
"The Company records a liability for the present value of the estimated future retirement costs associated with its natural gas and oil properties."
Asset retirement obligations are a company’s recorded promise to pay for dismantling, cleaning up, or restoring property when a long-lived asset is retired — for example decommissioning a plant or removing equipment. Companies estimate the future cleanup cost today and book it as a liability (and add the cost to the asset), so it affects the balance sheet, reported profits over time, and future cash needs; investors watch it like a planned bill that can reduce cash available for returns.
Monte Carlo simulation technical
"The fair value of the Company’s PSUs is determined using a Monte Carlo simulation model as of the grant date."
A Monte Carlo simulation is a computerized way to model many possible future outcomes by running thousands of randomized “what-if” scenarios, like rolling dice repeatedly to see the range of results. For investors it shows the probability of different returns, losses, or timing outcomes under varied assumptions, helping quantify uncertainty and compare risk — similar to using many practice runs to judge how often a plan succeeds or fails.
debt service coverage ratio financial
"if the debt service coverage ratio (DSCR) is below 1.45 to 1.00, then 100%"
Debt service coverage ratio measures how many times a company's available cash flow can pay its scheduled debt payments (interest plus principal). Think of it like checking how many months of take-home pay it would take to cover your mortgage and loan bills; a higher number means a bigger cushion against missed payments. Investors use it to gauge credit risk, the likelihood of default, and whether a company can afford dividends or new borrowing.
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FAQ
How did Diversified Energy Company (DEC) perform financially in the first half of 2026?
DEC reported total revenue of $ 839,052 (in thousands) for the six months ended June 30, 2026, up from $ 649,212 (in thousands) a year earlier, and net income attributable to DEC of $ 86,332 (in thousands) versus a prior-year net loss.
What were DEC's cash flows for the six months ended June 30, 2026?
DEC generated net cash provided by operating activities of $ 257,516 (in thousands), used $ 101,506 (in thousands) in investing activities and used $ 197,735 (in thousands) in financing activities, ending with total cash, cash equivalents and restricted cash of $ 103,385 (in thousands).
What major acquisitions and divestitures did DEC complete in 2026?
In 2026 DEC acquired Sheridan assets for $ 236,387 (in thousands) and other assets for $ 18 million, and divested non-core Barnett assets for $ 116 million, Arkansas assets for $ 15 million, and undeveloped acreage for $ 126 million, recording related gains and losses on properties.
How much debt does DEC have and what are its key borrowing arrangements?
As of June 30, 2026, DEC had total borrowings of $ 2,978,729, including ABS VIII–XII notes, $ 500,000 of Nordic Bonds, a $ 195,300 Credit Facility balance with a $ 900 million borrowing base, and other miscellaneous borrowings of $ 37,486.
What share repurchases and dividends has DEC undertaken recently?
For the six months ended June 30, 2026, DEC repurchased 5,978,251 shares of common stock for about $ 84 million and paid cash dividends to stockholders totaling $ 43,034 (in thousands). In August 2026, the board declared a $0.29 per share cash dividend payable December 31, 2026.
What is the Camino acquisition described by DEC (ticker DEC)?
On July 2, 2026, DEC completed the acquisition of Camino-related producing properties and undeveloped acreage for a gross purchase price of approximately $1.2 billion, funded by $ 895 million of ABS notes issued by a special purpose vehicle and equity contributions from DEC and Carlyle.
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
For the quarterly period ended June 30, 2026
or
For the transition period from to
Commission file number: 001-41870
(Exact name of registrant as specified in its charter) | ||||
State or other jurisdiction of incorporation or organization | (I.R.S. Employer Identification No.) | |||
(Address of principal executive offices) | (Zip Code) | |||
Registrant’s telephone number, including area code: | ( |
Securities registered, pursuant to Section 12(b) of the Act:
Title of each class | Trading Symbol(s) | Name of each exchange on which registered | ||
Securities registered, pursuant to Section 12(g) of the Act: None
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 þ 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). Yes þ No ¨
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.
þ | Accelerated filer | ¨ | Non-accelerated filer | ¨ | |||||
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 þ
The registrant had 70,769,563 shares of common stock outstanding (excluding shares held by the Employee Benefit Trust) as of August 5, 2026.
Table of Contents
Page | ||
Part I | Financial Information | |
Item 1. | Financial Statements | 4 |
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 29 |
Item 3. | Quantitative and Qualitative Disclosures About Market Risk | 41 |
Item 4. | Controls and Procedures | 42 |
Part II | Other Information | |
Item 1. | Legal Proceedings | 43 |
Item 1A. | Risk Factors | 43 |
Item 2. | Unregistered Sales of Equity Securities and Use of Proceeds | 44 |
Item 3. | Defaults Upon Senior Securities | 44 |
Item 4. | Mine Safety Disclosures | 44 |
Item 5. | Other Information | 44 |
Item 6. | Exhibits | 45 |
Signatures | 46 |
Table of Contents | Form 10-Q | Diversified Energy Company |
Glossary of Terms
ABS - Asset-Backed Security
ASU - Accounting Standards Update
Bbl - Barrel or barrels of oil or natural gas liquids
Btu - A British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one
degree Fahrenheit.
E&P - Exploration and production
EBITDAX - Earnings before interest, tax, depreciation, amortization and exploration expense
EPS - Earnings per share
GAAP - U.S. Generally Accepted Accounting Principles
Henry Hub - A natural gas pipeline delivery point that serves as the benchmark natural gas price underlying NYMEX natural gas
futures contracts.
MBbls - Thousand barrels
Mcf - Thousand cubic feet of natural gas
Mcfe - Thousand cubic feet of natural gas equivalent
Midstream - Midstream activities include the processing, storing, transporting and marketing of natural gas, NGLs and oil.
MMbtu - Million British thermal units
MMcf - Million cubic feet of natural gas
MMcfe - Million cubic feet of natural gas equivalent
MMcfepd - Million cubic feet of natural gas equivalent per day
Mont Belvieu - A mature trading hub with a high level of liquidity and transparency that sets spot and futures prices for NGLs.
NGLs - Natural gas liquids, such as ethane, propane, butane and natural gasoline that are extracted from natural gas production
streams.
NYMEX - New York Mercantile Exchange
NYSE - New York Stock Exchange
Oil - Includes crude oil and condensate
PSU - Performance-based restricted stock unit
Realized price - The cash market price, less all expected quality, transportation and demand adjustments.
RSU - Time-based restricted stock unit
SOFR - Secured Overnight Financing Rate
Upstream - Upstream activities include exploration, discovery, and extraction of natural gas, NGLs, and oil. Often referred to as
exploration and production activities, or E&P.
WTI - West Texas Intermediate grade crude oil, used as a pricing benchmark for sales contracts and NYMEX oil futures contracts.
Table of Contents | Form 10-Q | Diversified Energy Company |
Cautionary Statement Regarding Forward-Looking Statements
This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of the U.S. Private Securities Litigation
Reform Act of 1995 that can be identified by the following terminology, including the terms “may,” “might,” “will,” “could,”
“would,” “should,” “expect,” “plan,” “anticipate,” “intend,” “seek,” “believe,” “estimate,” “predict,” “potential,” “continue,”
“contemplate,” “possible,” or the negative of these terms or other variations or comparable terminology, or by discussions of strategy,
plans, objectives, goals, future events or intentions. These forward-looking statements include all matters that are not historical facts.
They appear in a number of places throughout this Quarterly Report on Form 10-Q and include, but are not limited to, statements
regarding our intentions, beliefs or current expectations concerning, among other things, our results of operations, financial positions,
liquidity, prospects, growth strategies, future acquisitions or dispositions, and the natural gas and oil industry. By their nature,
forward-looking statements involve risk and uncertainty because they relate to future events and circumstances.
Forward-looking statements are not guarantees of future performance and the actual results of our operations, financial position and
liquidity, and the development of the markets and the industry in which we operate, may differ materially from those described in, or
suggested by, the forward-looking statements contained in this Quarterly Report on Form 10-Q. In addition, even if the results of
operations, financial position and liquidity, and the development of the markets and the industry in which we operate are consistent
with the forward-looking statements contained in this Quarterly Report on Form 10-Q, those results or developments may not be
indicative of results or developments in subsequent periods. A number of factors could cause results and developments to differ
materially from those expressed or implied by the forward-looking statements including, without limitation, general economic and
business conditions, the behavior of other market participants, industry trends, competition, commodity prices, changes in regulation,
currency fluctuations, our ability to recover our reserves, our ability to successfully integrate acquisitions, our ability to obtain
financing to meet liquidity needs, changes in our business strategy, and political and economic uncertainty.
Forward-looking statements may, and often do, differ materially from actual results. No representation is made that any of these
statements or forecasts will come to pass or that any forecast results will be achieved. Any forward-looking statements in this
Quarterly Report on Form 10-Q speak only as of the date of this Quarterly Report on Form 10-Q, reflect our current view with respect
to future events and are subject to risks relating to future events and other risks, uncertainties and assumptions relating to our
operations, results of operations, growth strategy and liquidity. Investors should specifically consider the factors identified in this
Quarterly Report on Form 10-Q and in other documents that we file with or furnish to the SEC which could cause actual results to
differ. We explicitly disclaim any obligation or undertaking to revise any forward-looking statements in this Quarterly Report on Form
10-Q that may occur due to any change in our expectations or to reflect events or circumstances after the date of this Quarterly Report
on Form 10-Q except as may be required by applicable law.
4
Table of Contents | Form 10-Q | Diversified Energy Company |
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
Page | |
Condensed Consolidated Financial Statements (Unaudited) | 5 |
Condensed Consolidated Balance Sheets | 5 |
Condensed Consolidated Statements of Comprehensive Income (Loss) | 6 |
Condensed Consolidated Statements of Changes in Stockholders' Equity | 7 |
Condensed Consolidated Statements of Cash Flows | 8 |
Notes to the Condensed Consolidated Financial Statements | 9 |
5
Table of Contents | Condensed Consolidated Financial Statements (Unaudited) | Diversified Energy Company |
Condensed Consolidated Balance Sheets (Unaudited)
As of | ||
(In thousands, except par and share data) | June 30, 2026 | December 31, 2025 |
ASSETS | ||
Current assets: | ||
Cash and cash equivalents | $ | $ |
Restricted cash | ||
Accounts receivable, net | ||
Derivatives | ||
Prepaid expenses and other current assets | ||
Total current assets | $ | $ |
Noncurrent assets: | ||
Natural gas and oil properties (successful efforts method): | ||
Proved natural gas and oil properties | $ | $ |
Unproved natural gas and oil properties | ||
Accumulated depletion | ( | ( |
Natural gas and oil properties, net | ||
Property, plant, and equipment, net | ||
Operating right of use assets | ||
Restricted cash | ||
Derivatives | ||
Deferred tax assets | ||
Other assets | ||
Total assets | $ | $ |
LIABILITIES AND STOCKHOLDERS' EQUITY | ||
Current liabilities: | ||
Accounts payable | $ | $ |
Accrued liabilities | ||
Revenue to be distributed | ||
Current portion of long-term debt, net | ||
Operating lease liabilities | ||
Derivatives | ||
Derivatives settlements payable | ||
Other current liabilities | ||
Total current liabilities | $ | $ |
Noncurrent liabilities: | ||
Asset retirement obligations | $ | $ |
Operating lease liabilities | ||
Long-term debt, net | ||
Derivatives | ||
Other liabilities | ||
Total liabilities | $ | $ |
Commitments and contingent liabilities (Note 12) | ||
Stockholders' equity: | ||
Common stock ($ issued and outstanding) | $ | $ |
Additional paid in capital | ||
Accumulated other comprehensive income (loss) | ( | ( |
Retained earnings (accumulated deficit) | ( | ( |
Total stockholders' equity attributable to DEC | $ | $ |
Noncontrolling interests | ||
Total stockholders' equity | $ | $ |
Total liabilities and stockholders' equity | $ | $ |
The accompanying notes are an integral part of the Condensed Consolidated Financial Statements.
6
Table of Contents | Condensed Consolidated Financial Statements (Unaudited) | Diversified Energy Company |
Condensed Consolidated Statements of Comprehensive Income (Loss) (Unaudited)
(In thousands, except share and per share data) | Three Months Ended | Six Months Ended | ||
June 30, 2026 | June 30, 2025 | June 30, 2026 | June 30, 2025 | |
Revenue | ||||
Natural gas | $ | $ | $ | $ |
NGLs | ||||
Oil | ||||
Total commodity revenue | $ | $ | $ | $ |
Gain (loss) on derivatives | ( | ( | ||
Midstream | ||||
Other | ||||
Total revenue | $ | $ | $ | $ |
Operating expense | ||||
Lease operating expense | $( | $( | $( | $( |
Production taxes | ( | ( | ( | ( |
Midstream operating expense | ( | ( | ( | ( |
Transportation expense | ( | ( | ( | ( |
Accretion of asset retirement obligation | ( | ( | ( | ( |
General and administrative expense | ( | ( | ( | ( |
Depreciation, depletion and amortization | ( | ( | ( | ( |
Gain (loss) on natural gas and oil properties and equipment | ||||
Total operating expense | $( | $( | $( | $( |
Income (loss) from operations | $ | $ | $ | $ |
Other income (expense) | ||||
Interest expense | $( | $( | $( | $( |
Loss on debt extinguishment | ( | ( | ( | |
Other income (expense) | ||||
Income (loss) before taxation | $ | $ | $ | $( |
Income tax benefit (expense) | ( | ( | ||
Net income (loss) | $ | $ | $ | $( |
Other comprehensive income (loss) | ( | |||
Total comprehensive income (loss) | $ | $ | $ | $( |
Net income (loss) attributable to: | ||||
DEC | $ | $ | $ | $( |
Noncontrolling interest | ||||
Net income (loss) | $ | $ | $ | $( |
Earnings (loss) per share attributable to DEC | ||||
Basic | $ | $ | $ | $( |
Diluted | $ | $ | $ | $( |
Weighted average shares outstanding | ||||
Basic | ||||
Diluted | ||||
The accompanying notes are an integral part of the Condensed Consolidated Financial Statements.
7
Table of Contents | Condensed Consolidated Financial Statements (Unaudited) | Diversified Energy Company |
Condensed Consolidated Statements of Changes in Stockholders’ Equity (Unaudited)
Total Stockholders' Equity Attributable to DEC | ||||||||
Accumulated Other Comprehensive Income (Loss) | Retained Earnings (Accumulated Deficit) | |||||||
Additional Paid in Capital | Total Stockholders' Equity | |||||||
Common Stock | Noncontrolling Interest | |||||||
(In thousands, except share data) | Shares | Amount | ||||||
Balance as of December 31, 2024 | $ | $ | $( | $( | $ | $ | $ | |
Net income (loss) | — | — | — | — | ( | ( | ( | |
Other comprehensive income (loss) | — | — | — | ( | — | ( | — | ( |
Issuances of common stock | — | — | — | |||||
Repurchases of common stock | ( | — | ( | — | — | ( | — | ( |
Share-based compensation | — | — | ( | — | ||||
Dividends declared | — | — | — | ( | — | |||
Distributions to noncontrolling interest owners | — | — | — | — | — | — | ( | ( |
Balance as of March 31, 2025 | $ | $ | $( | $( | $ | $ | $ | |
Net income (loss) | — | — | — | — | ||||
Other comprehensive income (loss) | — | — | — | — | — | |||
Issuances of common stock | — | — | ( | — | — | ( | — | ( |
Repurchases of common stock | ( | ( | ( | — | — | ( | — | ( |
Share-based compensation | — | — | ( | — | ||||
Dividends declared | — | — | ( | — | ( | ( | — | ( |
Distributions to noncontrolling interest owners | — | — | — | — | — | — | ( | ( |
Balance as of June 30, 2025 | $ | $ | $( | $( | $ | $ | $ | |
Balance as of December 31, 2025 | $ | $ | $( | $( | $ | $ | $ | |
Net income (loss) | — | — | — | — | ( | ( | ( | ( |
Repurchases of common stock | ( | ( | ( | — | — | ( | — | ( |
Share-based compensation | — | ( | — | |||||
Dividends declared | — | — | ( | — | ( | ( | — | ( |
Distributions to noncontrolling interest owners | — | — | — | — | — | — | ( | ( |
Balance as of March 31, 2026 | $ | $ | $( | $( | $ | $ | $ | |
Net income (loss) | — | — | — | — | ||||
Repurchases of common stock | ( | ( | ( | — | — | ( | — | ( |
Share-based compensation | — | — | ( | — | ||||
Dividends declared | — | — | — | ( | ( | — | ( | |
Distributions to noncontrolling interest owners | — | — | — | — | — | — | ( | ( |
Balance as of June 30, 2026 | $ | $ | $( | $( | $ | $ | $ | |
The accompanying notes are an integral part of the Condensed Consolidated Financial Statements.
8
Table of Contents | Condensed Consolidated Financial Statements (Unaudited) | Diversified Energy Company |
Condensed Consolidated Statements of Cash Flows (Unaudited)
Six Months Ended | ||
(In thousands) | June 30, 2026 | June 30, 2025 |
Cash flows from operating activities: | ||
Net income (loss) | $ | $( |
Adjustments to reconcile net income (loss) to cash flows from operating activities: | ||
Depreciation, depletion and amortization | ||
Accretion of asset retirement obligations | ||
Income tax (benefit) expense | ( | |
(Gain) loss on derivatives | ||
Cash proceeds (payments) on settlement of derivatives | ( | ( |
Settlement of asset retirement costs | ( | ( |
(Gain) loss on natural gas and oil properties and equipment | ( | ( |
Loss on early retirement of debt | ||
Non-cash share-based compensation | ||
Other | ||
Changes in working capital: | ||
Accounts receivable, net | ( | |
Other assets | ( | ( |
Accounts payable | ( | |
Other liabilities | ( | ( |
Net cash provided by operating activities | $ | $ |
Cash flows from investing activities: | ||
Consideration for business acquisitions, net of cash acquired | $ | $( |
Consideration for asset acquisitions, net of cash acquired | ( | ( |
Proceeds from divestitures | ||
Capital expenditures | ( | ( |
Net cash (used in) investing activities | $( | $( |
Cash flows from financing activities: | ||
Repayment of borrowings | $( | $( |
Proceeds from borrowings | ||
Prepayment charge on early retirement of debt | ( | |
Debt issuance costs | ( | ( |
Hedge modifications associated with ABS Notes | ( | ( |
Proceeds from equity issuance, net | ||
Principal element of lease payments | ( | ( |
Dividends to stockholders | ( | ( |
Distributions to noncontrolling interest owners | ( | ( |
Repurchases of common stock (stock repurchase program) | ( | ( |
Repurchases of common stock by the EBT, net | ( | |
Net cash (used in) provided by financing activities | $( | $ |
Net change in cash, cash equivalents and restricted cash | ( | |
Cash, cash equivalents and restricted cash, beginning of period | ||
Cash, cash equivalents and restricted cash, end of period | $ | $ |
Cash and cash equivalents | ||
Restricted cash | ||
Total cash, cash equivalents and restricted cash | $ | $ |
The accompanying notes are an integral part of the Condensed Consolidated Financial Statements.
9
Table of Contents | Notes to the Condensed Consolidated Financial Statements (Unaudited) | Diversified Energy |
Index to the Notes to the Condensed Consolidated Financial Statements (Unaudited)
Note 1 - Basis of Presentation and Summary of Significant Accounting Policies | 9 | Note 8 - Compensation Plans | 19 | |
Note 2 - Acquisitions & Divestitures | 10 | Note 9 - Asset Retirement Obligations | 20 | |
Note 3 - Income Tax | 14 | Note 10 - Borrowings | 21 | |
Note 4 - Earnings (Loss) Per Share | 14 | Note 11 - Fair Value | 26 | |
Note 5 - Natural Gas & Oil Properties | 15 | Note 12 - Commitments & Contingencies | 27 | |
Note 6 - Derivatives | 15 | Note 13 - Supplemental Cash Flow Information | 28 | |
Note 7 - Stockholders' Equity | 18 | Note 14 - Subsequent Events | 28 |
Diversified Energy Company, a Delaware corporation (“Diversified,” “DEC,” “we,” “us,” “our,” or collectively with its wholly owned
subsidiaries, the “Company”) is an independent energy company engaged in the development, production, transportation and
marketing of natural gas, oil and NGLs. The Company’s assets are located in the United States within the following geographical
operating areas:
•Appalachian Region, which spans Ohio, Indiana, Pennsylvania, Virginia, West Virginia, Kentucky, Tennessee and Alabama;
•Central Region, which includes Texas, Oklahoma, New Mexico, and Louisiana;
•Other, which includes Florida and Wyoming.
accounting principles (“GAAP”) and the rules and regulations of the Securities and Exchange Commission (the “SEC”). Pursuant to
statements should be read in conjunction with the audited consolidated financial statements and notes thereto for the year ended
December 31, 2025, as included in the Company’s Annual Report on Form 10-K. The accompanying unaudited condensed
consolidated financial statements reflect all normal recurring adjustments that, in the opinion of management, are necessary for a fair
statement of our condensed consolidated financial statements and accompanying notes and include the accounts of our direct and
indirect wholly owned subsidiaries and entities in which we have a controlling financial interest. Intercompany accounts and balances
have been eliminated.
Certain reclassifications have been made to prior period financial statements and related disclosures to conform to current period
presentation. These reclassifications have no impact on previously reported total assets, total liabilities, net income or total operating
cash flows.
In accordance with ASC 280, Segment Reporting, the Company determines its operating segments based on the components of the
business regularly reviewed by the chief executive officer, who serves as the chief operating decision maker (“CODM”), for purposes
of resource allocation and performance assessment. The CODM evaluates the Company’s operations in a consolidated manner.
Accordingly, the Company has one reportable segment.
The CODM uses consolidated income (loss) before income taxes to allocate resources and assess operating performance, and is also
regularly provided information on lease operating expense, transportation expense, production taxes, and general and administrative
expense, which represent significant segment expenses. Other segment items primarily consist of depreciation, depletion and
amortization, interest expense, and income tax expense (benefit). These amounts are derived from, and can be found within, the
Company’s Condensed Consolidated Statements of Comprehensive Income (Loss).
Segment profit or loss reconciles directly to consolidated income (loss) before income taxes, with no reconciling items.
The Company’s reportable segment, CODM, segment performance measures, and segment assets remain materially unchanged from
those reported in the Company’s Annual Report on Form 10-K for the year ended December 31, 2025.
10
Table of Contents | Notes to the Condensed Consolidated Financial Statements (Unaudited) | Diversified Energy |
Cash and cash equivalents consist of highly liquid investments with an original maturity of three months or less. The Company
maintains cash balances at financial institutions, which at times may exceed federally insured limits. The Company has not
experienced any losses in such accounts and believes it faces no significant credit risk related to cash and cash equivalents.
The Company classifies cash as restricted when contractual or regulatory requirements limit its withdrawal or use for general
corporate purposes. The Company presents restricted cash as either a current or noncurrent asset based on the expected timing of the
related obligations.
Restricted cash primarily consists of:
•Amounts the Company holds as collateral for surety bonds or that state agencies require for well abandonment obligations; and
•Cash reserves the Company maintains for interest payments and fees related to its asset-backed securitization arrangements,
which an independent indenture trustee administers.
The Company’s accounting policy and the nature of its restricted cash arrangements remain consistent with those described in the
Company’s Annual Report on Form 10-K for the year ended December 31, 2025, with no material changes during the interim period.
ASU Number | Description | Effective Date |
ASU 2024-04 | Debt—Debt with Conversion and Other Options | January 1, 2026 |
ASU 2025-05 | Measurement of credit losses for accounts receivable and contract assets from transactions accounted for under Topic 606 | January 1, 2026 |
The adoption of these standards did not significantly impact the Company’s Condensed Consolidated Financial Statements.
Financial Statements:
ASU Number | Description | Effective Date | Impact on Financial Statements |
ASU 2026-02 | Environmental Credits and Environmental Credit Obligations (Topic 818) | January 1, 2028 | The Company is assessing the impact, but does not expect a material effect. |
The Company will adopt this standard on the effective date. Based on preliminary assessment, the Company does not expect the
adoption of this standard to have a material impact on its consolidated financial statements.
On April 30, 2026, the Company acquired certain oil and natural gas wells, leasehold interests and related assets from Sheridan. Given
the concentration of assets, this transaction was considered an asset acquisition rather than a business combination. The Company paid
net consideration of $236 million, inclusive of customary purchase price adjustments. The transaction was funded through proceeds
from the Company’s Credit Facility (as defined below).
Refer to Note 10 for additional information regarding borrowings.
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Table of Contents | Notes to the Condensed Consolidated Financial Statements (Unaudited) | Diversified Energy |
fair values as of April 30, 2026 were as follows (in thousands):
Consideration paid | |
Cash consideration | $ |
Total consideration | $ |
Net assets acquired | |
Natural gas and oil properties | $ |
Property, plant and equipment, net | |
Derivatives, net | |
Accounts receivable, net | |
Asset retirement obligations | ( |
Other current liabilities | ( |
Net assets acquired | $ |
During the six months ended June 30, 2026, the Company collectively acquired certain midstream and plugging assets for total
consideration of $18 million, inclusive of customary purchase price adjustments, and transaction costs.
On June 15, 2026, the Company divested certain non-core Barnett assets for net proceeds of $116 million after customary purchase
price adjustments. The proceeds received exceeded the carrying amount of the net assets divested resulting in a gain on natural gas and
oil properties and equipment of $19 million.
Additionally, on April 20, 2026, the company divested certain non-core assets in Arkansas for net proceeds of $15 million after
customary purchase price adjustments.
During the six months ended June 30, 2026, the Company divested certain non-core undeveloped acreage for consideration of $126
million. The consideration received exceeded the carrying amount of the net assets divested resulting in a gain on natural gas and oil
properties and equipment of $125 million. Additionally, the disposal of various wells and property, plant and equipment in the normal
course of business resulted in cash proceeds of $2 million and a loss on natural gas and oil properties and equipment of $10 million.
On November 24, 2025, the Company acquired Canvas. The Company determined that substantially all of the fair value of the gross
assets acquired was concentrated in a single asset group; therefore, the transaction was accounted for as an asset acquisition. The
Company paid purchase consideration of $533 million, inclusive of customary purchase price adjustments. The purchase consideration
consisted of the issuance of 3,718,209 shares of common stock and $399 million in cash, inclusive of transaction costs of $13 million.
On the date of the acquisition, the Company settled the outstanding balance of $81 million on Canvas’s credit facility.
Refer to Notes 7 and 10 for additional information regarding stockholders’ equity and borrowings.
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fair values as of November 24, 2025 were as follows (in thousands):
Consideration paid | |
Cash consideration | $ |
Fair value of common stock issued(a) | |
Payoff existing credit facility | |
Total consideration | $ |
Net assets acquired | |
Cash | $ |
Natural gas and oil properties | |
Property, plant and equipment, net | |
Other noncurrent assets | |
Accounts receivable, net | |
Other current assets | |
Asset retirement obligations | ( |
Deferred tax liability | ( |
Other noncurrent liabilities | ( |
Accounts payable | ( |
Other current liabilities | ( |
Net assets acquired | $ |
(a)The fair value of the common stock issued was based on the closing price of the Company’s common stock on November 24, 2025
of $14.51 . The fair value of our common stock is a Level 1 input as our stock price is a quoted price in an active market.
On March 14, 2025, the Company acquired Maverick. The Company determined the transaction did not have a significant
concentration of assets and that it acquired an identifiable set of inputs, processes, and outputs. As a result, the Company concluded
the transaction was a business combination. The Company paid purchase consideration of approximately $666 million, inclusive of
customary purchase price adjustments. The purchase consideration consisted of the issuance of 21,194,213 shares of common stock
and $211 million in cash. As part of the acquisition, the Company paid off on the acquisition date the $202 million balance
outstanding on Maverick’s credit facility and assumed $518 million of ABS Maverick Notes outstanding. Transaction costs associated
with the acquisition were $21 million and are included within G&A expense in the Consolidated Statements of Comprehensive
Income (Loss).
Refer to Notes 7 and 10 for additional information regarding stockholders’ equity and borrowings.
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2025 were as follows (in thousands):
Consideration paid | |
Cash consideration | $ |
Fair value of common stock issued(a) | |
Payoff existing credit facility | |
Total consideration | $ |
Net assets acquired | |
Cash | $ |
Natural gas and oil properties | |
Property, plant and equipment, net | |
Restricted cash | |
Other noncurrent assets | |
Derivatives, net | |
Accounts receivable, net | |
Other current assets | |
Asset retirement obligations | ( |
Borrowings | ( |
Other noncurrent liabilities | ( |
Accounts payable | ( |
Accrued operating expenses | ( |
Revenues payable | ( |
Other current liabilities | ( |
Net assets acquired | $ |
(a)The fair value of the common stock issued was based on the closing price of the Company’s common stock on March 14, 2025 of
$11.95 . The fair value of our common stock is a Level 1 input as our stock price is a quoted price in an active market.
The fair value of the natural gas and oil properties was based on estimated future production volumes, adjusted for risk characteristics
associated with the classification of the acquired reserves, and related future net cash flows discounted using a weighted average cost
of capital. The Company utilized NYMEX strip pricing adjusted for inflation. Management utilized the assistance of a third-party
valuation expert to estimate the fair value of the natural gas and oil properties acquired. The Company considers the discount rate,
commodity pricing, production and operating expense to be the assumptions most sensitive to the fair value of the acquired natural gas
and oil properties and represent Level 3 inputs, other than NYMEX strip pricing which represents a Level 1 input.
On February 27, 2025, the Company acquired certain upstream assets and related infrastructure within Virginia, West Virginia, and
Alabama of the Appalachian Region from Summit. Given the concentration of assets, this transaction was considered an asset
acquisition rather than a business combination. The Company paid consideration of $42 million, inclusive of transaction costs of $0.4
million and customary purchase price adjustments, substantially all of which was accounted for as natural gas and oil properties. The
transaction was funded through proceeds from the ABS X Notes collateralized, in part, by the acquired assets. Refer to Note 10 for
additional information regarding borrowings.
During the six months ended June 30, 2025, the Company acquired certain midstream and upstream assets that are contiguous to its
existing Central Region assets. The Company paid total consideration of $16 million, inclusive of non-cash consideration of $4
million, customary purchase price adjustments, and transaction costs. Given the concentration of assets, these transactions were
considered asset acquisitions rather than business combinations.
During the six months ended June 30, 2025, the Company divested certain non-core undeveloped acreage across its operating footprint
for consideration of $70 million. The consideration received exceeded the carrying amount of the net assets divested resulting in a gain
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Income tax expense during interim periods is based on applying an estimated annual effective income tax rate to year-to-date income,
plus any significant unusual or infrequently occurring items which are recorded in the interim period. The provision for income taxes
for the six months ended June 30, 2026 and 2025 differs from the amount that would be provided by applying the statutory U.S.
federal income tax rate of 21% to pre-tax income primarily due to the impact of federal tax credits (principally the marginal well tax
credit), state income taxes, permanent differences, and discrete items recognized in the interim period.
The effective tax rates for the six months ended June 30, 2026 and 2025 were (17.7 )% and (16.2 )%, respectively. For the six months
ended June 30, 2026, we reported a tax benefit of $13 million, a change of $17 million, compared to a tax expense of $3 million for
the six months ended June 30, 2025. The effective tax rate for the six months ended June 30, 2026 was primarily impacted by the
recognition of the federal marginal well tax credit available to qualified producers and by management’s estimate of the annual
effective tax rate expected for the full financial year. The federal government provides these credits to encourage companies to
continue producing lower-volume wells during periods of low prices to maintain the underlying jobs they create and the state and local
tax revenues they generate for communities to support schools, social programs, law enforcement and other similar public services.
Six Months Ended | ||
June 30, 2026 | June 30, 2025 | |
U.S. federal statutory tax rate | ||
State income taxes, net of federal tax benefit | ||
Federal credits(a) | ( | ( |
Other, net | ||
Effective tax rate | ( | ( |
(a)Federal tax credits consist primarily of the marginal well tax credit. Because the credit is a dollar amount determined
independently of pre-tax results, its impact, expressed as a percentage of pre-tax income (loss), can be positive or negative based
on the Company's forecasted annual pre-tax book income (loss) used in the estimated annual effective tax rate.
Basic earnings (loss) per share (“EPS”) is calculated by dividing net income (loss) attributable to common shareholders by the
weighted average number of shares of common stock outstanding during the period, excluding shares held in treasury (if any) and held
by the Employee Benefit Trust established by the Company in March 2022 to benefit its employees (“EBT”). Diluted EPS reflects the
potential dilution that could occur if share-based compensation awards were exercised or converted into shares, except when their
effect would be anti-dilutive. Refer to Note 7 for additional information regarding the EBT.
the periods presented:
(In thousands, except share and per share data) | Three Months Ended | Six Months Ended | ||
June 30, 2026 | June 30, 2025 | June 30, 2026 | June 30, 2025 | |
Net income (loss) attributable to DEC | $ | $ | $ | $( |
Weighted average shares outstanding - basic | ||||
Dilutive impact of potential shares | ||||
Weighted average shares outstanding - diluted | ||||
Basic earnings (loss) per share | $ | $ | $ | $( |
Diluted earnings (loss) per share | $ | $ | $ | $( |
Potentially dilutive shares(a) | ||||
(a)Share-based compensation awards excluded from the diluted EPS calculation because their effect would have been anti-dilutive.
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Table of Contents | Notes to the Condensed Consolidated Financial Statements (Unaudited) | Diversified Energy |
As of | |
(In thousands) | June 30, 2026 |
Costs | |
Beginning balance | $ |
Additions(a) | |
Disposals(b) | ( |
Ending balance | $ |
Depletion and impairment | |
Beginning balance | $( |
Depletion expense | ( |
Disposals(b) | |
Ending balance | $( |
Net book value | $ |
(a)During the six months ended June 30, 2026, the Company’s additions primarily consisted of the Sheridan acquisition in April
2026 as well as development and recurring capital expenditures.
(b)During the six months ended June 30, 2026, the Company’s disposals primarily consisted of the sale of the Barnett assets in June
2026.
Refer to Note 2 for additional information regarding acquisitions and divestitures.
The Company faces volatility in market prices and basis differentials for natural gas, NGLs and oil, affecting the predictability of its
cash flows from commodity sales. Additionally, the Company’s cash flows related to interest payments on variable rate debt
obligations can be impacted by fluctuations in interest rate markets, depending on its debt structure. To manage these risks, the
Company enters into derivative contracts primarily with major financial institutions and energy trading counterparties. As of June 30,
2026, these instruments included swaps, collars, basis swaps, and stand-alone put and call options. The Company does not intend to
hold or issue derivative financial instruments for speculative trading purposes and has elected not to designate any of its derivative
instruments for hedge accounting treatment. Below is a description of these instruments:
Swaps: | When the Company sells a swap, it agrees to receive a fixed price for the contract while paying a floating market price to the counterparty; |
Collars: | Arrangements that include a fixed floor price (purchased put option) and a fixed ceiling price (sold call option) based on an index price have no net costs overall. At the contract settlement date, (1) when the index price is higher than the ceiling price, the Company pays the counterparty the difference between the index price and ceiling price, (2) when the index price is between the floor and ceiling prices, no payments are due from either party, and (3) when the index price is below the floor price, the Company will receive the difference between the floor price and the index price. Some collar arrangements may also include a sold put option with a strike price below the purchased put option. Known as a three-way collar, the structure operates similarly to the standard collar. However, when the index price settles below the sold put option, the Company pays the counterparty the difference between the index price and sold put option, effectively enhancing realized pricing by the difference between the price of the sold and purchased put options; |
Basis swaps: | Arrangements that guarantee a price differential for commodities from a specified delivery point. When the Company sells a basis swap, it receives a payment from the counterparty if the price differential exceeds the stated terms of the contract. Conversely, if the price differential is less than the stated terms, the Company pays the counterparty; |
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Put options: | The Company purchases and sells put options in exchange for a premium. When the Company purchases a put option, it receives from the counterparty the excess amount (if any) by which the market price falls below the strike price of the put option at the time of settlement. If the market price is above the put option’s strike price, no payment is required from either party. Conversely, when the Company sells a put option, it pays the counterparty the excess amount (if any) by which the market price falls below the strike price of the put option at the time of settlement. If the market price is above the put option’s strike price, no payment is required from either party; |
Call options: | The Company purchases and sells call options in exchange for a premium. When the Company purchases a call option, it receives from the counterparty the excess amount (if any) by which the market price exceeds the strike price of the call option at the time of settlement. If the market price is below the call option’s strike price, no payment is required from either party. When the Company sells a call option, it pays the counterparty the excess amount (if any) by which the market price exceeds the strike price of the call option at the time of settlement. If the market price is below the call option’s strike price, no payment is required from either party; and |
The Company may elect to enter into offsetting transactions for the above instruments for the purpose of cancelling or terminating
certain positions.
As of June 30, 2026 | ||
(In thousands, except volume data) | Volume | Fair Value |
Natural gas (MMbtu) | ||
Swaps | $( | |
Two-way collars | ( | |
Three-way collars | ( | |
Stand-alone calls(a) | ( | |
Basis swaps | ( | |
Purchased puts | ||
Sold puts | ( | |
Total natural gas | $( | |
NGLs (MBbls) | ||
Swaps | $( | |
Stand-alone calls | ( | |
Total NGLs | $( | |
Oil (MBbls) | ||
Swaps | $( | |
Three-way collars | ( | |
Sold calls | ( | |
Total oil | $( | |
Interest | ||
SOFR interest rate swap ($ | $ | |
Total interest | $ | |
Total fair value of derivatives | $( | |
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Table of Contents | Notes to the Condensed Consolidated Financial Statements (Unaudited) | Diversified Energy |
arrangement. The Company elected to present these derivative assets and liabilities on a net basis when these conditions are satisfied.
(In thousands) | As of | |
Derivatives | Consolidated Statement of Financial Position | June 30, 2026 |
Assets: | ||
Current assets | Derivatives | $ |
Noncurrent assets | Other assets | |
Total assets | $ | |
Liabilities | ||
Current liabilities | Derivatives | $( |
Noncurrent liabilities | Derivatives | ( |
Total liabilities | $( | |
Net assets (liabilities): | ||
Net assets (liabilities) - current | Derivatives | $( |
Net assets (liabilities) - noncurrent | Other assets / Derivatives | ( |
Total net assets (liabilities) | $( |
The Company presents the fair value of derivative contracts on a net basis in the Consolidated Statement of Financial Position. Below
is the impact of this presentation on the Company’s recognized assets and liabilities for the date presented:
As of June 30, 2026 | |||
(In thousands) | Presented without Effects of Netting | Effects of Netting | As Presented with Effects of Netting |
Current assets | $ | $( | $ |
Noncurrent assets | ( | ||
Total assets | $ | $( | $ |
Current liabilities | ( | ( | |
Noncurrent liabilities | ( | ( | |
Total liabilities | $( | $ | $( |
Total net assets (liabilities) | $( | $— | $( |
Income (Loss) for the specified periods:
Three Months Ended | Six Months Ended | |||
(In thousands) | June 30, 2026 | June 30, 2025 | June 30, 2026 | June 30, 2025 |
Net gain (loss) on commodity derivatives settlements | $( | $ | $( | $( |
Net gain (loss) on interest rate swaps | ||||
Total gain (loss) on settled derivatives(a) | $( | $ | $( | $( |
Gain (loss) on fair value adjustments of unsettled derivatives(b) | ( | ( | ||
Total gain (loss) on derivatives | $ | $ | $( | $( |
(a)Represents the cash settlement of derivatives that were settled during the period.
(b)Represents the change in fair value of derivatives, net of the carrying value of derivatives that were settled during the period.
All derivatives are classified as Level 2 instruments under ASC 820, as their valuation relies on observable market inputs other than
quoted prices. For further details related to fair value measurements, refer to Note 11.
Occasionally, such as during the acquisition of producing assets, the completion of ABS financings, or in response to fluctuating price
environments, the Company may strategically modify, offset, terminate, or expand certain existing hedge positions. These
modifications can involve changes to the volume of production covered by contracts, the swap or strike price of specific derivative
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contracts, and other similar aspects of the derivative agreements. The Company manages distinct, long-dated derivative contract
portfolios for its ABS financings and term loans. Additionally, the Company maintains a separate derivative contract portfolio for
assets secured by the Credit Facility. These derivative contract portfolios associated with the Company’s ABS financings, term loans,
and Credit Facility are presented in the Company’s Statement of Financial Position.
In June 2026, the Company paid $8 million to modify contracts associated with the ABS IV Notes in connection with their
extinguishment. As these modifications were associated with a borrowing transaction, these amounts are presented as a financing
activity in the Consolidated Statement of Cash Flows. Refer to Note 10 for additional information regarding borrowings.
In February 2025, the Company adjusted portions of its commodity derivative portfolio across its legal entities for approximately
$150 million in connection with the completion of the ABS X financing arrangement. The Company made further adjustments to its
commodity derivative portfolio for approximately $21 million for the retirement of the ABS I and Term Loan I financing
arrangements (each as previously defined in the Company’s Annual Report on Form 10-K for the year ended December 31, 2025).
Refer to Note 10 for additional information regarding borrowings.
The Company is authorized to issue up to 350,000,000 0.01
December 31, 2025, the Company had 71,388,065 76,979,625
The Company is authorized to issue 30,000,000 shares of preferred stock, par value $0.01 per share. No
outstanding.
In March 2025, the Company announced the completion of its previously announced acquisition of Maverick. The transaction was
funded in part through the issuance of 21,194,213 new shares of common stock directly to the unitholders of Maverick. The total value
of the stock consideration was $253 million, excluding transaction costs of $0.4 million, based on the Company’s stock price on the
NYSE on the closing date of the Maverick transaction.
In February 2025, the Company issued 8,500,000 new shares of common stock at $14.50 per share to raise gross proceeds of $123
million, excluding transaction costs of $6 million. The Company used the net proceeds to repay a portion of the debt incurred in
connection with the Maverick acquisition.
For further details related to acquisitions, refer to Note 2.
The Company’s holdings in its own equity instruments are classified as treasury stock. The consideration paid, along with any directly
attributable incremental costs, is deducted from the Company’s stockholders’ equity until the shares are either cancelled or reissued.
No gain or loss is recognized in the Consolidated Statements of Comprehensive Income (Loss) upon the purchase, sale, issuance, or
cancellation of treasury stock.
In March 2022, the Company established the EBT to benefit its employees. The Company provides funding to the EBT to facilitate the
acquisition of shares. These shares are held in the EBT to fulfill awards and grants under the Company’s 2017 and 2025 Equity
Incentive Plans and the Employee Stock Purchase Plan (the “ESPP”). Shares held in the EBT are treated in the same manner as
treasury stock and are thus included in the Condensed Consolidated Financial Statements as treasury stock. No
by the EBT during the six months ended June 30, 2026 and 2025. As of June 30, 2026, the EBT held a total of 1,662,012 shares. For
further details related to share-based compensation, refer to Note 8.
During the six months ended June 30, 2026, the Company repurchased 5,978,251 shares of common stock at an average price of
$14.08 per share, amounting to a total of $84 million and representing 8 % of common stock issued and outstanding as of June 30,
2026. During the six months ended June 30, 2025, the Company repurchased 2,581,827 shares of common stock at an average price of
$13.33 per share, amounting to a total of $34 million and representing 3 % of common stock issued and outstanding as of June 30,
2025.
The Company has recorded the repurchase of these shares of common stock as a reduction in common stock and additional paid in
capital. All repurchased shares of common stock were cancelled upon repurchase. As of June 30, 2026 and December 31, 2025, the
par value of the cancelled shares was retired from common stock in the Condensed Consolidated Balance Sheets.
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Table of Contents | Notes to the Condensed Consolidated Financial Statements (Unaudited) | Diversified Energy |
Dividends are declared at the discretion of the Board of Directors and are subject to applicable law and contractual restrictions.
Dividends are paid to holders of record as of the record date. Dividends are waived on shares held in the EBT.
The Company’s ability to pay dividends is subject to certain restrictions under its Credit Facility and other debt agreements, which
may limit dividend payments based on leverage ratios and other financial covenants. Refer to Note 10 for additional information.
The 2017 Equity Incentive Plan (the “2017 Plan”), as amended through April 9, 2025, authorized issuances up to 10 % of the
Company’s outstanding common stock and had 3,947,882 shares subject to outstanding awards as of November 21, 2025. On that
date, the Company adopted the 2025 Equity Incentive Plan (the “2025 Plan”), which authorized and reserved 6,892,551
common stock, consisting of 2,944,669 newly authorized shares plus shares underlying outstanding awards under the 2017 Plan that
may become available upon forfeiture, cancellation, expiration, cash settlement, or withholding for taxes or exercise prices. Upon
adoption of the 2025 Plan, no further awards may be granted under the 2017 Plan, and only shares underlying awards outstanding as
of November 21, 2025 may be issued thereunder. As of June 30, 2026, 1,386,664 shares remained available for grant under the 2025
Plan, under which all future equity awards will be made.
Number of Shares | Weighted Average Grant Date Fair Value per Share | |
Balance as of December 31, 2025 | $ | |
Granted | ||
Vested | ( | |
Forfeited | ||
Balance as of March 31, 2026 | ||
Granted | ||
Vested | ||
Forfeited | ( | |
Balance as of June 30, 2026 | $ |
During the six months ended June 30, 2026, the total fair value of RSUs at the date of vesting was $3 million. As of June 30, 2026, the
Company had $28 million of unrecognized share-based compensation expense related to RSUs that will be recognized over a weighted
average period of 1.6 years.
RSUs can vest either on a cliff basis or ratably, depending on the service conditions. The fair value of the Company’s RSUs is
calculated using the closing price of our common stock on the NYSE at the grant date. This value is then expensed uniformly over the
vesting period.
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Table of Contents | Notes to the Condensed Consolidated Financial Statements (Unaudited) | Diversified Energy |
Number of Shares | Weighted Average Grant Date Fair Value per Share | |
Balance as of December 31, 2025 | $ | |
Granted | ||
Vested | ( | |
Forfeited | ||
Balance as of March 31, 2026 | $ | |
Granted | ||
Vested | ||
Forfeited | ( | |
Balance as of June 30, 2026 | $ |
During the six months ended June 30, 2026, the total fair value of PSUs at the date of vesting was $2 million. As of June 30, 2026, the
Company had $11 million of unrecognized share-based compensation expense related to PSUs that will be recognized over a weighted
average period of 1.6 years.
PSUs are subject to cliff vesting based on specific performance criteria over a three-year period. Depending on the achievement of
these performance targets, the number of units that will vest can vary from 0 % to 250 % of the initial award.
value is then expensed uniformly over the vesting period. For PSUs granted during the respective periods presented, the inputs to the
Monte Carlo model included the following:
Six Months Ended | ||
June 30, 2026 | June 30, 2025 | |
Risk-free rate of interest | ||
Volatility(a) | ||
Correlation with comparator group range | ||
(a)Volatility utilizes the historical volatility for the Company’s share price.
Three Months Ended | Six Months Ended | |||
(In thousands) | June 30, 2026 | June 30, 2025 | June 30, 2026 | June 30, 2025 |
RSUs | $ | $ | $ | $ |
PSUs | ||||
ESPP | ||||
Total share-based compensation expense | $ | $ | $ | $ |
properties. Additionally, the Company records a liability for the future retirement costs of its production facilities and pipelines when
required by contract, statute, or legal obligation. For the six months ended June 30, 2026, no state contractual agreements or statutes
related to production facilities and pipelines are expected to impose material obligations on the Company.
In estimating the present value of future retirement costs for its natural gas and oil properties, the Company considers several factors,
including the number and state jurisdictions of wells, current retirement costs by state and well type, and the Company’s retirement
plan, which is based on state requirements and the Company’s capacity to retire wells over their productive lives. The Company’s
assumptions are grounded in the current economic environment and are believed to provide a reasonable basis for estimating the future
liability. However, actual retirement costs will ultimately depend on future market prices at the time the retirement services are
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Table of Contents | Notes to the Condensed Consolidated Financial Statements (Unaudited) | Diversified Energy |
performed. Additionally, the timing of retirement will vary based on when the fields cease to produce economically, which is
influenced by future natural gas and oil prices and the retirement schedule. These factors are inherently uncertain.
The Company incorporates annual inflationary cost increases into its current cost expectations and then discounts the resulting cash
Six Months Ended | |
(In thousands) | June 30, 2026 |
Balance at beginning of period | $ |
Additions(a) | |
Accretion expense | |
Asset retirement costs | ( |
Disposals(b) | ( |
Revisions | ( |
Balance at end of period | $ |
Less: Current asset retirement obligations | |
Noncurrent asset retirement obligations | $ |
(a)Additions primarily relate to the Sheridan acquisition.
(b)Disposals primarily relate to the Barnett assets divestiture.
Instrument | Interest Rate | June 30, 2026 | |
Credit Facility | (a) | ||
ABS VIII Notes | |||
ABS IX Notes | |||
ABS X Notes | |||
ABS XI Notes | |||
ABS XII Notes | |||
Nordic Bonds | |||
Other miscellaneous borrowings(b) | |||
Total borrowings | $ | ||
Less: Current portion of long-term debt | ( | ||
Less: Deferred financing costs | ( | ||
Less: Original issue discounts | ( | ||
Total noncurrent borrowings, net | $ | ||
(a)Represents a variable interest rate based on utilization.
(b)Includes $20 million in notes payable issued by a third party financial institution in November 2024, collateralized by two natural
gas processing plants and various natural gas compressors and related support equipment in the Central Region, as of June 30,
2026.
The Company maintains a Credit Facility with a lending syndicate, the borrowing base for which is redetermined semi-annually or in
certain other situations as described therein. The Company’s wholly owned subsidiary, DP RBL Co LLC, serves as the borrower
under the Credit Facility. The borrowing base is primarily determined by the value of the natural gas and oil properties that serve as
collateral for the lending arrangement, and it may fluctuate due to changes in collateral, which can result from acquisitions or the
establishment of ABS, term loans, or other lending structures.
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Table of Contents | Notes to the Condensed Consolidated Financial Statements (Unaudited) | Diversified Energy |
As of June 30, 2026, the Company’s Credit Facility had a borrowing base of $900 million and a maturity of March 2029. The Credit
Facility has an interest rate of SOFR plus an additional spread ranging from 2.75 % to 3.75 % based on utilization. Interest payments on
the Credit Facility are paid on a quarterly basis. Available borrowings under the Credit Facility were $669 million as of June 30, 2026,
which excludes $35 million in letters of credit issued to certain vendors.
In February 2022, the Company formed Diversified ABS IV LLC (“ABS IV”), a limited-purpose, bankruptcy-remote, wholly-owned
subsidiary, to issue asset-backed securities with a total principal amount of $160 million at par (the “ABS IV Notes”). The ABS IV
Notes were secured by a portion of the upstream producing assets acquired through the Blackbeard acquisition. The ABS IV Notes
had an annual interest rate of 4.95 % and a legal final maturity date of February 2037. Both interest and principal payments on the ABS
IV Notes were made on a monthly basis.
In June 2026, the ABS IV Notes were repaid and retired from the Company’s outstanding debt in connection with the Company’s
divestiture of its Barnett assets.
In October 2022, the Company formed Diversified ABS VI LLC (“ABS VI”), a limited-purpose, bankruptcy-remote, wholly-owned
subsidiary, to issue, jointly with Oaktree Capital Management, L.P. (“Oaktree”), asset-backed securities with a total principal amount
of $460 million. The Company’s share amounted to $236 million before fees, reflecting its 51.25 % ownership interest in the collateral
assets (the “ABS VI Notes”). The ABS VI Notes were issued at a 2.63 % discount and were primarily secured by the upstream assets
jointly acquired with Oaktree in the Tapstone acquisition. The Company recorded its proportionate share of the ABS VI Notes in its
Condensed Consolidated Balance Sheets. In June 2024, as part of the Oaktree acquisition, the Company assumed Oaktree’s
proportionate debt of $133 million associated with the ABS VI Notes.
The ABS VI Notes carried an annual interest rate of 7.50 % and had a legal final maturity date of November 2039. Both interest and
principal payments on the ABS VI Notes were made on a monthly basis.
In May 2026, the ABS VI Notes were repaid and retired from the Company’s outstanding debt in connection with the issuance of the
ABS XII Notes (as defined below).
In May 2024, the Company formed Diversified ABS VIII LLC (“ABS VIII”), a limited-purpose, bankruptcy-remote, wholly-owned
subsidiary, to issue Class A-1 and Class A-2 asset-backed securities (the “Class A-1 ABS VIII Notes,” “Class A-2 ABS VIII Notes,”
and collectively the “ABS VIII Notes”). The Class A-1 Notes were issued with a total principal amount of $400 million, while the
Class A-2 ABS VIII Notes were issued with a total principal amount of $210 million. The proceeds from these issuances were used to
repay the outstanding principal of the ABS III & ABS V notes, effectively retiring those notes from the Company’s outstanding debt.
Consequently, ABS III and ABS V were dissolved. The ABS VIII Notes are secured by the collateral that previously secured the ABS
III and ABS V notes, which includes certain upstream producing and midstream assets in the Appalachian Region owned by the
Company, and the remaining upstream assets in the Appalachian Region that were not securitized by previous ABS transactions.
The Class A-1 ABS VIII Notes carry an annual interest rate of 7.076 %, while the Class A-2 ABS VIII Notes carry an annual interest
rate of 7.670 %. These notes have an anticipated repayment date of May 2029 and a legal final maturity date of May 2044. Both
interest and principal payments on the ABS VIII Notes are made on a monthly basis.
the debt service coverage ratio (the “DSCR”) is below 1.45 to 1.00, then 100 %, (ii) if the DSCR is between 1.45 to 1.00 and 1.50 to
1.00, then 50 %, or (iii) if the DSCR is at least 1.50 to 1.00, then 25 %; (b) if the production tracking rate is below 80 %, then 100 %,
otherwise 25 %; or (c) if the loan-to-value ratio (“LTV”) exceeds 75 %, then 100 %, otherwise 25 %.
In June 2024, the Company formed DP Mustang Holdco LLC, a limited-purpose, bankruptcy-remote, wholly-owned subsidiary (“ABS
IX,” formerly “ABS Facility Warehouse”), to secure a bridge loan facility (the “ABS Facility Warehouse Notes”). The initial draw on
the ABS Facility Warehouse Notes amounted to $71 million, which included $66 million in net proceeds, $3 million in restricted cash
interest reserve, and $2 million in debt issuance costs. The ABS Facility Warehouse Notes were secured by certain producing assets
that previously collateralized the Credit Facility. It carried an interest rate of SOFR plus an additional 3.75 % and had a legal final
maturity date of May 2029. Both interest and principal payments on the ABS Facility Warehouse Notes were made on a monthly
basis.
In September 2024, the Company issued Class A and Class B asset-backed securities (the “Class A ABS IX Notes,” “Class B ABS IX
Notes,” and collectively the “ABS IX Notes”) with a total principal amount of $77 million. The Class A ABS IX Notes were issued
with a total principal amount of $71 million, while the Class B ABS IX Notes were issued with a total principal amount of $6 million.
The proceeds from these issuances were used to repay the outstanding principal of the ABS Facility Warehouse Notes, effectively
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retiring it from the Company’s outstanding debt and resulting in a loss on the early retirement of debt amounting to $2 million. The
Class A ABS IX Notes carry an annual interest rate of 6.555 % and have an anticipated repayment date of September 2029 and a legal
final maturity date of September 2044. The Class B ABS IX Notes carry an annual interest rate of 11.235 %. Both interest and
principal payments on the ABS IX Notes are made on a monthly basis.
DSCR at the applicable payment date is below 1.45 to 1.00, then 100 %, (ii) if the DSCR is between 1.45 to 1.00 and 1.55 to 1.00, then
cash flow remaining after the payments ranking senior to them.
In February 2025, the Company formed Diversified ABS Phase X LLC, a limited-purpose, bankruptcy-remote, wholly-owned
subsidiary (“ABS X”), to issue Class A-1, Class A-2, and Class B asset-backed securities (the “Class A-1 ABS X Notes,” “Class A-2
ABS X Notes,” “Class B ABS X Notes,” and collectively the “ABS X Notes”) with a total principal amount of $530 million. The
Class A-1 ABS X Notes were issued with a total principal amount of $200 million. The Class A-2 ABS X Notes were issued with a
total principal amount of $240 million. The Class B ABS X Notes were issued with a total principal amount of $90 million. The
proceeds from these issuances were used to repay the outstanding principal of the ABS I Notes, ABS II Notes, and Term Loan I,
effectively retiring those notes from the Company’s outstanding debt. The ABS X Notes are secured by certain upstream producing
assets in the Appalachian Region owned by the Company, including those that previously collateralized the ABS I Notes, ABS II
Notes, and Term Loan I. Excess proceeds from the issuance of the Notes were used to fund the Summit acquisition and for general
corporate purposes. Refer to Note 2 for additional information regarding acquisitions.
The Class A-1 ABS X Notes carry an annual interest rate of 5.945 %. The Class A-2 ABS X Notes carry an annual interest rate of
February 2030 and a legal final maturity date of February 2045. Both interest and principal payments on the ABS X Notes are made
on a monthly basis.
DSCR as of the applicable payment date is below 1.45 to 1.00, then 100 %, (ii) if the DSCR is between 1.45 to 1.00 and 1.55 to 1.00,
then 50 %, or (iii) if the DSCR is at least 1.55 to 1.00, then 32.5 %; (b) if the production tracking rate is below 80 %, then 100 %,
otherwise 32.5 %; (c) if the LTV exceeds 80 %, then 100 %, and (ii) if the LTV exceeds 75 % but is not more than 80 %, then 50 %,
otherwise 32.5 %; or (d) if the aggregate LTV exceeds 90 %, then 100 %. In addition, while the Class A Notes remain outstanding, the
Class B Notes receive a minimum allocation of 15 % of the excess cash flow remaining after the payments ranking senior to them.
In February 2025, the Company formed Maverick ABS Holdings LLC, a limited-purpose, bankruptcy-remote, wholly-owned
subsidiary (“ABS Maverick”), to hold the Class A-1, Class A-2, and Class B asset-backed securities (the “Class A-1 ABS Maverick
Notes,” “Class A-2 ABS Maverick Notes,” “Class B ABS Maverick Notes,” and collectively the “ABS Maverick Notes”) assumed as
part of the Maverick acquisition. These Notes had a total principal amount of $640 million upon issuance. The Class A-1 ABS
Maverick Notes were issued with a total principal amount of $285 million. The Class A-2 ABS Maverick Notes were issued with a
total principal amount of $260 million. The Class B ABS Maverick Notes were issued with a total principal amount of $95 million.
Upon acquisition, the ABS Maverick Notes carried a 1.6 % market premium and were secured by certain upstream producing assets in
the Western Anadarko Basin acquired in the Maverick acquisition. Refer to Note 2 for additional information regarding acquisitions.
The Class A-1 ABS Maverick Notes had an annual interest rate of 8.121 %. The Class A-2 ABS Maverick Notes had an annual interest
rate of 8.946 %. The Class B ABS Maverick Notes had an annual interest rate of 12.436 %. These notes had a legal final maturity date
of December 2038. Both interest and principal payments on the ABS Maverick Notes were made on a monthly basis.
In May 2026, the ABS Maverick Notes were repaid and retired from the Company’s outstanding debt in connection with the issuance
of the ABS XII Notes (as defined below).
In November 2025, the Company formed DP Keeneland Mile LLC, a limited-purpose, bankruptcy-remote, wholly-owned subsidiary
(“ABS XI”), to issue Class A-1, Class A-2, and Class B asset-backed securities (the “Class A-1 ABS XI Notes,” “Class A-2 ABS XI
Notes,” “Class B ABS XI Notes,” and collectively the “ABS XI Notes”) with a total principal amount of $400 million. The Class A-1
ABS XI Notes were issued with a total principal amount of $247 million. The Class A-2 ABS XI Notes were issued with a total
principal amount of $91 million. The Class B ABS XI Notes were issued with a total principal amount of $62 million. The proceeds
from this issuance were used to fund, in part, the Canvas acquisition and are secured by certain upstream producing assets acquired.
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The Class A-1 ABS XI Notes carry an annual interest rate of 5.757 %. The Class A-2 ABS XI Notes carry an annual interest rate of
November 2030 and a legal final maturity date of November 2045. Both interest and principal payments on the ABS XI Notes are
made on a monthly basis.
DSCR is below 1.15 to 1.00, then 100 %, (ii) if the DSCR is between 1.15 to 1.00 and 1.45 to 1.00, then 50 %, or (iii) if the DSCR is at
least 1.45 to 1.00, then 33 %; (b) if the production tracking rate is below 80 %, then 100 %, otherwise 33 %; or (c) if the LTV exceeds
allocation of 17.5 % of the excess cash flow remaining after the payments ranking senior to them.
In May 2026, the Company formed DP Red River LLC, a limited-purpose, bankruptcy-remote, wholly-owned subsidiary (“ABS
XII”), to issue Class A-1 and Class A-2 asset-backed securities (the “Class A-1 ABS XII Notes,” “Class A-2 ABS XII Notes,” and
collectively the “ABS XII Notes”) with a total principal amount of $850 million. The Class A-1 ABS XII Notes were issued with a
total principal amount of $590 million. The Class A-2 ABS XII Notes were issued with a total principal amount of $260 million. The
proceeds from this issuance were used to repay the outstanding principal of the ABS Maverick Notes and ABS VI Notes, pay any
related premiums, fees, and expenses and for general corporate purposes. The ABS XII Notes are secured by specific upstream
producing assets in the Western Anadarko Basin that previously collateralized the ABS Maverick Notes and ABS VI Notes.
The Class A-1 ABS XII Notes carry an annual interest rate of 6.016 %. The Class A-2 ABS XII Notes carry an annual interest rate of
principal payments on the ABS XII Notes are made on a monthly basis.
trigger, the required allocation is 45 % for the first 24 months following closing, 55 % for months 25 through 36, and 60 % thereafter, in
each case increased by 10 percentage points if the DSCR is below 1.75 to 1.00. The allocation increases to 100 % if (a) the DSCR is
below 1.45 to 1.00, (b) the production tracking rate is below 85 %, (c) the LTV is at or above 85 % during the first 36 months following
closing, 80 % during months 37 through 48, or 75 % thereafter, or (d) a rapid amortization event has occurred and is continuing.
In April 2025, the Company issued the Nordic Bonds, consisting of $300 million of new senior secured notes in the Nordic bond
market at a 2 % discount, resulting in net proceeds of $294 million (the “Nordic Bonds”). The proceeds were used to repay existing
indebtedness and for general corporate purposes. The Nordic Bonds mature in April 2029 and bear interest at a fixed rate of 9.75 % per
annum, payable semi-annually in arrears. The Bonds are secured by (i) all of the Company’s U.S. bank accounts, (ii) the equity
interests in Diversified Gas and Oil Company (“DGOC”) as well as DGOC’s equity interests in its direct operating subsidiaries and
(iii) interests in certain intercompany loans.
The Nordic Bonds were listed for trading on the Oslo Stock Exchange in October 2025.
In February 2026, the Company completed a $200 million tap-on offering, increasing the aggregate principal amount of the
outstanding Nordic Bonds to $500 million. The additional Bonds were issued at a 3.5 % discount, resulting in net proceeds of $193
million before transaction costs and other fees. The proceeds were used for general corporate purposes. The additional Nordic Bonds
were listed for trading on the Oslo Stock Exchange in July 2026.
In February 2025, the Company used proceeds from the ABS X Notes to repay the outstanding principal of the ABS I & II notes and
Term Loan I (each as previously defined in the Company’s Annual Report on Form 10-K for the year ended December 31, 2025),
thereby retiring the ABS I & II notes and Term Loan I from the Company’s outstanding debt and resulting in a loss on the early
retirement of debt of $27 million. Concurrently, Diversified ABS Holdings LLC, Diversified ABS Phase II Holdings LLC, and DP
Bluegrass Holdings LLC were dissolved. The ABS X Notes are secured by the collateral previously securing the ABS I & II notes,
along with a portion of the collateral previously securing Term Loan I.
In March 2025, the Company used proceeds from the upsized borrowing base on the amended and restated credit agreement governing
the Credit Facility to repay the outstanding principal on Term Loan II (as previously defined in the Company’s Annual Report on
Form 10-K for the year ended December 31, 2025), thereby retiring Term Loan II from the Company’s outstanding debt and resulting
in a loss on the early retirement of debt of $0.2 million.
In May 2026, the Company used proceeds from the ABS XII Notes to repay the outstanding principal of the ABS Maverick Notes and
ABS VI Notes, thereby retiring the ABS Maverick Notes and ABS VI Notes from the Company’s outstanding debt resulting in a loss
on the early retirement of debt of $21 million. Concurrently, Maverick ABS Holdings LLC and Diversified ABS VI LLC were
dissolved. The ABS XII Notes are secured by the collateral previously securing the ABS Maverick Notes and ABS VI Notes.
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In June 2026, the Company used proceeds from the Barnett assets divestiture to repay the outstanding principal of the ABS IV Notes,
thereby retiring the ABS IV Notes from the Company’s outstanding debt and resulting in a loss on the early retirement of debt of
$2 million. Concurrently, Diversified ABS IV LLC was dissolved.
Credit Facility
The Credit Facility contains certain customary representations and warranties and affirmative and negative covenants, including
covenants relating to: maintenance of books and records; financial reporting and notification; compliance with laws; maintenance of
properties and insurance; and limitations on incurrence of indebtedness, liens, fundamental changes, international operations, asset
sales, making certain debt payments and amendments, restrictive agreements, investments, restricted payments and hedging. The
restricted payment provision governs the Company’s ability to make discretionary payments such as dividends, share repurchases, or
other discretionary payments. DP RBL Co LLC must comply with the following restricted payments test in order to make
discretionary payments (i) leverage is less than 1.5 x and borrowing base availability is >20 %, or (ii) leverage is between 1.5 x and
payments are prohibited.
Additional covenants require DP RBL Co LLC to maintain a ratio of total debt to EBITDAX of not more than 3.25 to 1.00 and a ratio
of current assets (with certain adjustments) to current liabilities of not less than 1.00 to 1.00 as of the last day of each fiscal quarter.
As of June 30, 2026, the Company was in compliance with all covenants for its Credit Facility.
ABS VIII, IX, X, XI, and XII Notes (Collectively, the “ABS Notes”) and the Nordic Bonds
The ABS Notes and Nordic Bonds are governed by a series of covenants and restrictions typical for such transactions, including (i) the
requirement for the issuer to maintain specified reserve accounts to ensure the payment of interest on the ABS Notes and Nordic
Bonds, (ii) provisions for optional and mandatory prepayments, specified make-whole payments under certain conditions, (iii)
covenants related to recordkeeping, access to information and similar matters, and (iv) compliance with all applicable laws and
regulations.
The ABS Notes have an anticipated repayment date, which occur between May 2029 and May 2031, that precedes their legal final
maturity date. The Company currently expects to repay or refinance each such series on or prior to its anticipated repayment date.
If a series of ABS Notes is not repaid or refinanced by its anticipated repayment date, an accelerated amortization event occurs under
the applicable indenture. In that event, substantially all cash flow generated by the assets securing that series, after payment of senior
fees, hedge amounts, interest and scheduled principal, is applied to repay principal of that series and is not available for distribution to
the Company, and an additional amount accrues on the outstanding notes of that series at a rate of 2 % per annum above the applicable
stated interest rate. The failure to repay a series of ABS Notes on its anticipated repayment date is not an event of default under the
applicable indenture, and does not accelerate, or constitute a default under, any other series of ABS Notes, the Credit Facility or the
Nordic Bonds.
The ABS Notes and Nordic Bonds are also subject to customary accelerated amortization events as outlined in the agreements
governing such indebtedness. These events may include failure to maintain specified debt service coverage or loan to value ratios,
failure to meet certain production metrics, certain change of control and management services agreement termination events, and non-
compliance with hedging requirements, as applicable.
The ABS Notes and Nordic Bonds are subject to customary events of default, which may include, as applicable, non-payment of
required interest, principal, or other amounts due, failure to comply with covenants within specified time frames, certain bankruptcy
events, breaches of specified representations and warranties, failure of security interests to be effective, and failure of the indebtedness
to be redeemed upon a change in control event.
Additionally, the Nordic Bonds contain the following financial covenants (i) the leverage ratio shall not exceed 3.5 x, (ii) the asset
coverage ratio shall not be less than 1.20 to 1.00, (iii) book equity shall not be less than $500 million, and (iv) liquidity shall not be
less than 25 % of the outstanding bonds.
As of June 30, 2026, the Company was in compliance with all covenants related to the ABS Notes and Nordic Bonds.
costs, premiums, and discounts, and does not reflect the effect of the anticipated repayment dates of the ABS Notes, which occur
between May 2029 and May 2031:
(in thousands) | Remainder of 2026 | 2027 | 2028 | 2029 | 2030 | Thereafter | Total debt |
Debt maturity | $ | $ | $ | $ | $ | $ | $ |
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Three Months Ended | Six Months Ended | |||
(In thousands) | June 30, 2026 | June 30, 2025 | June 30, 2026 | June 30, 2025 |
Interest incurred | ||||
Borrowings | $ | $ | $ | $ |
Other | ||||
Total interest incurred | ||||
Less: Capitalized interest | ( | ( | ( | ( |
Interest expense | $ | $ | $ | $ |
As of | |
(in thousands) | June 30, 2026 |
Credit Facility(a) | $ |
ABS notes(b) | |
Nordic Bonds(b) | |
Other miscellaneous borrowings(a) | |
Total fair value of outstanding debt | $ |
(a)Carrying value approximates fair value.
(b)Fair values are measured using a market approach, based upon market rates, which are Level 2 inputs.
principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the
measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use
of unobservable inputs. To determine fair value, the Company applies a hierarchy that consists of three input levels. The first and
second levels are regarded as observable, while the third is categorized as unobservable. These input levels may be utilized in the
measurement of fair value as outlined below:
Level 1: | Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date. | ||
Level 2: | Inputs (other than quoted prices included in Level 1) can include the following: | ||
(1) Observable prices in active markets for similar assets or liabilities;
(2) Prices for identical assets or liabilities in markets that are not active;
(3) Directly observable market inputs for substantially the full term of the asset or liability; and
(4) Market inputs that are not directly observable but are derived from or corroborated by observable market data.
Level 3: | Unobservable inputs which reflect the Company’s best estimates of what market participants would use in pricing the asset or liability at the measurement date. | ||
There were no transfers between fair value levels for the three months ended June 30, 2026.
Derivatives
The Company measures the fair value of its derivatives in accordance with ASC 820, Fair Value Measurement, utilizing valuation
models that incorporate observable market inputs whenever available. These inputs typically include contractual terms, current market
prices, forward price curves for natural gas, liquids, and oil, relevant interest rate yield curves (such as U.S. Treasury and SOFR), and
volatility factors.
Derivatives are classified within the fair value hierarchy based on the observability of the inputs used in the valuation. The Company’s
fixed price swaps are classified as Level 2 and are valued using third-party discounted cash flow models, which rely on NYMEX
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futures for natural gas and oil derivatives and OPIS forward curves for NGL derivatives. Interest rate derivatives, also classified as
Level 2, are valued using discounted cash flow models that incorporate contracted notional amounts, market-quoted SOFR yield
curves, and credit-adjusted risk-free rates.
Options, including call options, put options, and collars, are classified as Level 2 and valued using the Black-Scholes option pricing
model. This model incorporates contract terms such as maturity, market parameters including NYMEX and OPIS futures, interest
rates, volatility, and counterparty credit risk. Volatility and other significant inputs are obtained from independent third-party pricing
sources and are subject to monthly verification.
Basis swaps are classified as Level 2 and are valued using third-party models based on forward commodity price curves.
Changes in key inputs, such as volatility, may result in changes to the fair value measurement of the Company’s derivatives.
As of June 30, 2026 | |||
(in thousands) | Level 1 | Level 2 | Level 3 |
Assets | |||
Derivatives | |||
Liabilities | |||
Derivatives | ( | ||
Total net assets (liabilities) | $ | $( | $ |
Impairment of Proved Natural Gas & Oil Properties
When impairment occurs, the Company estimates the fair value of the impaired proved natural gas and oil properties through a
discounted cash flow method, which incorporates Level 3 inputs that are not directly observable.
Business combinations
The Company assesses the value of acquired proved properties using an income-based approach as of the acquisition date. This
method is classified as a Level 3 fair value estimate due to its reliance on key assumptions, such as anticipated production volumes,
future commodity pricing, operating costs, weighted average cost of capital (the discount rate) and risk adjustments tailored to the
The carrying values of cash and cash equivalents, accounts receivable, other current assets, accounts payable, accrued liabilities, and
other current liabilities approximate fair value due to the highly liquid or short-term nature. The Company’s Credit Facility (see Note
10) has a recorded value that approximates fair market value, as it bears interest at a floating rate that approximates a current market
rate.
Delivery Commitments
We have contractually agreed to deliver firm quantities of natural gas to various customers, which we expect to fulfill with production
from existing reserves. To ensure we meet these commitments, we regularly monitor our proved developed reserves.
June 30, 2026.
Remainder of 2026 | 2027 | 2028 | 2029 | 2030 | Thereafter | Total | |
Natural gas (MMcf) |
Litigation and Regulatory Proceedings
The Company is involved in various pending legal issues that have arisen in the ordinary course of business. The Company accrues for
litigation, claims, and proceedings when a liability is both probable and the amount can be reasonably estimated. As of June 30, 2026,
the Company did not have any material amounts accrued related to litigation or regulatory matters.
For any matters not accrued for, it is not possible to estimate the amount of any additional loss or range of loss that is reasonably
possible. However, based on the nature of the claims, management believes that current litigation, claims, and proceedings are not,
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individually or in aggregate, after considering insurance coverage and indemnification, likely to have a material adverse impact on the
Company’s financial position, results of operations, or cash flows.
The Company has no other contingent liabilities that would have a material impact on the Company’s financial position, results of
operations, or cash flows.
Environmental Matters
The Company’s operations are subject to environmental laws and regulations in all the jurisdictions where it operates, and the
Company was in material compliance as of June 30, 2026. However, the Company is unable to predict the impact of additional
environmental laws and regulations that may be adopted in the future, including whether they would adversely affect its operations.
The Company can offer no assurance regarding the significance or cost of compliance associated with any new environmental
Six Months Ended | ||
(in thousands) | June 30, 2026 | June 30, 2025 |
Supplemental cash flow information: | ||
Cash paid for interest | $ | $ |
Cash paid for income taxes | ||
Cash paid for amounts included in the measurement of operating lease liabilities | ||
Cash paid for amounts included in the measurement of finance lease liabilities | ||
Supplemental disclosure of non-cash transactions: | ||
Issuance of common stock for acquisitions | $ | $ |
Additions to asset retirement obligations | ||
Right-of-use assets obtained in exchange for operating lease liabilities | ||
Right-of-use assets obtained in exchange for finance lease liabilities | ||
Cash paid for amounts included in the measurement of operating lease liabilities represents total lease payments made during the
period. For finance leases, cash paid for amounts included in the measurement of lease liabilities represents the principal portion of
lease payments. Interest paid on finance leases is included in cash paid for interest.
Natural Resources, LLC (“Camino”) that owned certain producing properties and undeveloped acreage for a gross purchase price of
approximately $1.2 billion before customary purchase price adjustments.
Simultaneously with the closing of the acquisition, the producing properties were contributed to an indirect subsidiary of a newly
formed special purpose vehicle (“SPV”), and the Company entered into an agreement with funds and accounts managed by Carlyle
Global Credit Investment Management, LLC (“Carlyle”) pursuant to which the Company and Carlyle hold 40 % and 60 % of the equity
interests in the SPV, respectively. Carlyle contributed $82 million and the Company contributed $55 million in exchange for their
respective equity interests in the SPV. The Company retained 100 % ownership in the undeveloped acreage.
The acquisition of the producing properties was funded by $895 million of ABS notes issued by the SPV and collateralized by the
producing properties, together with the equity contributions of the Company and Carlyle described above. The Company’s acquisition
of the undeveloped acreage, for approximately $170 million, was funded by cash on hand and borrowings under the Company’s Credit
Facility.
In August 2026, the Company’s Board of Directors declared a cash dividend on the Company’s common stock in the amount of $0.29
per share. The dividend is payable on December 31, 2026 to stockholders of record as of the close of business on December 2, 2026.
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of
Operations
The following discussion and analysis of financial condition and results of operations should be read in conjunction with the
Condensed Consolidated Financial Statements and the notes thereto included in this report. Unless the context otherwise indicates,
references to “Diversified,” the “Company,” “our,” “we” and “us” (i) for periods until the completion of the U.S. Domestication,
refer to Diversified Energy Company PLC and its consolidated subsidiaries, collectively, and (ii) for periods at or after the completion
of the U.S. Domestication, refer to Diversified Energy Company and its consolidated subsidiaries, collectively. For certain industry
specific terms used in this Quarterly Report on Form 10-Q, please refer to the Glossary of Terms.
In this discussion and analysis of financial condition and results of operations, we address topics such as acquisitions, tax matters,
derivatives, stockholders’ equity, asset retirement obligations, and borrowings. For more detailed information on these areas, refer to
Notes 2, 3, 6, 7, 9, and 10 within the Notes to the Condensed Consolidated Financial Statements. These notes provide comprehensive
disclosures and explanations that support the analysis presented in this section.
Recent Developments
•In July 2026, we completed the acquisition of the equity interests of certain affiliates of Camino Natural Resources, LLC
(“Camino”) that owned certain producing properties and undeveloped acreage for a gross purchase price of approximately $1.2
billion before customary purchase price adjustments. Refer to Note 14 for additional information regarding the Camino
acquisition.
•In June 2026, we divested certain non-core Barnett assets for net proceeds of $116 million after customary purchase price
adjustments. The proceeds received exceeded the carrying amount of the net assets divested resulting in a gain on natural gas and
oil properties and equipment of $19 million.
•In May 2026, we formed DP Red River LLC, a limited-purpose, bankruptcy-remote, wholly-owned subsidiary (“ABS XII”), to
issue asset-backed securities with a total principal amount of $850 million (the “ABS XII Notes”).
•In April 2026, we acquired certain oil and natural gas wells, leasehold interests and related assets from Sheridan Holding
Company III, LLC (“Sheridan”). We paid net consideration of $236 million, inclusive of customary purchase price adjustments.
•In April 2026, we completed the semi-annual borrowing base redetermination of the Credit Facility. The borrowing base under
the facility was increased from $825 million to $900 million as a result of the increase in collateral from certain assets acquired in
the Sheridan acquisition.
•For the six months ended June 30, 2026, we repurchased 5,978,251 shares, representing approximately 8% of the shares
outstanding as of June 30, 2026.
Market Conditions
Our business continued to be influenced by a range of external factors in 2026, including commodity price volatility, geopolitical
developments, and evolving supply and demand dynamics. We are a U.S. domestic energy producer focused primarily on the
production of natural gas. During the second quarter, Henry Hub natural gas prices remained volatile but averaged approximately
$2.90 per MMBtu, compared with an average of approximately $5.04 per MMBtu in the first quarter, reflecting lower prices as winter-
driven demand eased, partially offset by strong LNG export demand and the onset of summer cooling demand.
Geopolitical tensions, including the conflict involving Iran, the Russia-Ukraine war, and continued instability in the Middle East and
Venezuela, contributed to volatility in global energy markets and underscored the strategic importance of U.S. energy production. In
particular, uncertainty surrounding transit through the Strait of Hormuz contributed to market instability during the quarter.
Domestically, policy shifts continued to support U.S. energy development and LNG export growth, although tariffs on certain
imported steel, aluminum and derivative products introduced additional uncertainty around the cost of some equipment and materials.
Our vertically integrated model helps insulate us from certain direct impacts, and our hedging program continues to play an important
role in mitigating commodity price risk and supporting cash flow durability.
We also continued to monitor inflationary pressures, labor availability and supply chain conditions affecting the broader industry.
Despite ongoing market volatility and policy uncertainty, we remain focused on optimizing our asset base, managing costs and
enhancing operational efficiency. Our integrated model and strategic positioning continue to support our ability to navigate market
fluctuations and capitalize on long-term opportunities in the oil and natural gas sector.
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Results of Operations for the Three Months Ended June 30, 2026 Compared to the Three Months Ended
June 30, 2025
Production Volumes
Three Months Ended | ||||
June 30, 2026 | June 30, 2025 | Change | % Change | |
Net production | ||||
Natural gas (MMcf) | 80,715 | 76,638 | 4,077 | 5% |
NGLs (MBbls) | 2,862 | 2,318 | 544 | 23% |
Oil (MBbls) | 2,685 | 2,338 | 347 | 15% |
Total production (MMcfe)(a) | 113,997 | 104,574 | 9,423 | 9% |
Average daily production (MMcfepd) | 1,253 | 1,149 | 104 | 9% |
% Natural gas (Mcfe basis) | 71% | 73% | ||
(a)The basis for converting oil and NGL volumes (MBbls) to natural gas equivalent volumes (MMcfe) is determined by using the
ratio of one Bbl of oil or NGLs to six Mcf of natural gas.
The increase in production volumes for the three months ended June 30, 2026 compared to the three months ended June 30, 2025 was
primarily related to the Canvas and Sheridan acquisitions in the fourth quarter of 2025 and second quarter of 2026, respectively, as
well as our continued non-operated development investment. These increases were partially offset by normal production declines.
Commodity Pricing
Commodity prices fluctuate due to a range of factors outside of our control or ability to predict. These include, but are not limited to,
increased natural gas, NGLs and oil production levels that exceed market demand, adverse or unseasonable weather conditions,
geopolitical developments, macroeconomic events, and intensifying competition from other energy sources. Collectively, these
dynamics impact supply and demand, which ultimately determine the realized sales prices for our production. In addition to these
market-driven factors, our realized prices are affected by our derivative activities, commodity trades executed by non-physical trading
entities, and geographic variances in market pricing, including basis differentials. In response to these ongoing and evolving
conditions, we continuously monitor the commodity price environment. This disciplined approach is designed to preserve adequate
liquidity, uphold our financial flexibility, and protect long-term shareholder value across a range of pricing scenarios.
The following table summarizes our average realized sales prices and benchmark prices for the periods presented:
Three Months Ended | ||||
June 30, 2026 | June 30, 2025 | $ Change | % Change | |
Average realized sales prices (before derivative settlements) | ||||
Natural gas (Mcf) | $2.03 | $2.52 | $(0.49) | (19%) |
NGLs (Bbls) | 29.98 | 22.71 | 7.27 | 32% |
Oil (Bbls) | 94.67 | 63.81 | 30.86 | 48% |
Total (Mcfe) | $4.42 | $3.78 | $0.64 | 17% |
Average realized sales prices (after derivative settlements) | ||||
Natural gas (Mcf) | $2.52 | $2.65 | $(0.13) | (5%) |
NGLs (Bbls) | 21.67 | 22.15 | (0.48) | (2%) |
Oil (Bbls) | 65.96 | 66.34 | (0.38) | (1%) |
Total (Mcfe) | $3.88 | $3.91 | $(0.03) | (1%) |
Average benchmark prices | ||||
Henry Hub (Mcf) | $2.90 | $3.44 | $(0.54) | (16%) |
Mont Belvieu (Bbls) | 33.00 | 35.87 | (2.87) | (8%) |
WTI (Bbls) | 92.79 | 63.74 | 29.05 | 46% |
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Commodity Revenue
The following table reconciles the change in commodity revenue (excluding the impact of hedges settled in cash) by reflecting the
effect of changes in volume and in the underlying prices:
(In thousands) | Natural Gas | NGLs | Oil | Total |
Commodity revenue for the three months ended June 30, 2025 | $192,931 | $52,651 | $149,186 | $394,768 |
Volume increase (decrease) | 10,274 | 12,354 | 22,142 | 44,770 |
Price increase (decrease) | (39,509) | 20,808 | 82,863 | 64,162 |
Net increase (decrease) | (29,235) | 33,162 | 105,005 | 108,932 |
Commodity revenue for the three months ended June 30, 2026 | $163,696 | $85,813 | $254,191 | $503,700 |
Commodity revenue for the three months ended June 30, 2026 increased 28% compared to the three months ended June 30, 2025. The
increase was primarily related to the 17% increase in average realized sales prices, excluding the impact of derivatives settled in cash,
and the 9% increase in sold volumes primarily due to the acquisitions and non-operated development as discussed above.
Commodity Derivatives
To manage our cash flows in a volatile commodity price environment, we utilize commodity derivative contracts that enable us to
secure fixed per-unit sales prices for a portion of our production. As of June 30, 2026, approximately 86% of our production was fixed
through commodity derivative contracts over the next twelve months. The tables below set forth the impact of commodity derivatives
settlements on commodity revenue:
Three Months Ended June 30, 2026 | ||||||||
(In thousands, except per unit) | Natural Gas | NGLs | Oil | Total Commodity | ||||
Revenue | Realized $ | Revenue | Realized $ | Revenue | Realized $ | Revenue | Realized $ | |
Excluding hedge impact | $163,696 | $2.03 | $85,813 | $29.98 | $254,191 | $94.67 | $503,700 | $4.42 |
Gain (loss) on commodity derivatives settlements | 39,464 | 0.49 | (23,780) | (8.31) | (77,080) | (28.71) | (61,396) | (0.54) |
Including hedge impact | $203,160 | $2.52 | $62,033 | $21.67 | $177,111 | $65.96 | $442,304 | $3.88 |
Three Months Ended June 30, 2025 | ||||||||
(In thousands, except per unit) | Natural Gas | NGLs | Oil | Total Commodity | ||||
Revenue | Realized $ | Revenue | Realized $ | Revenue | Realized $ | Revenue | Realized $ | |
Excluding hedge impact | $192,931 | $2.52 | $52,651 | $22.71 | $149,186 | $63.81 | $394,768 | $3.78 |
Gain (loss) on commodity derivatives settlements | 10,011 | 0.13 | (1,307) | (0.56) | 5,913 | 2.53 | 14,617 | 0.13 |
Including hedge impact | $202,942 | $2.65 | $51,344 | $22.15 | $155,099 | $66.34 | $409,385 | $3.91 |
Gain (Loss) on Derivatives
The table below sets forth the impact of settlements and fair value adjustments on derivatives for the periods presented:
Three Months Ended | ||||
(In thousands) | June 30, 2026 | June 30, 2025 | $ Change | % Change |
Net gain (loss) on commodity derivatives settlements | $(61,396) | $14,617 | $(76,013) | (520%) |
Net gain (loss) on interest rate swaps | 17 | 35 | (18) | (51%) |
Total gain (loss) on settled derivatives(a) | $(61,379) | $14,652 | $(76,031) | (519%) |
Gain (loss) on fair value adjustments of unsettled derivatives(b) | 352,413 | 154,419 | 197,994 | 128% |
Total gain (loss) on derivatives | $291,034 | $169,071 | $121,963 | 72% |
(a)Represents the cash settlement of derivatives that were settled during the period.
(b)Represents the change in fair value of derivatives, net of the carrying value of derivatives that were settled during the period.
The change in this metric was driven by an increase in the fair value of unsettled derivatives due to lower forward commodity prices
primarily for natural gas. This increase was partially offset by a decrease in the value of settled derivatives due to increased oil
commodity prices during the period.
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Operating Expenses
Three Months Ended June 30, | Total Change | Per Mcfe Change | ||||||
(In thousands, except per unit data) | 2026 | Per Mcfe | 2025 | Per Mcfe | $ | % | $ | % |
Lease operating expenses | $141,242 | $1.24 | $131,184 | $1.25 | $10,058 | 8% | $(0.01) | (1)% |
Production taxes | 29,660 | 0.26 | 23,317 | 0.22 | 6,343 | 27% | 0.04 | 18% |
Midstream operating expenses | 20,439 | 0.18 | 19,361 | 0.19 | 1,078 | 6% | (0.01) | (5)% |
Transportation expenses | 24,383 | 0.21 | 23,769 | 0.23 | 614 | 3% | (0.02) | (9)% |
Accretion of asset retirement obligation | 13,481 | 0.12 | 10,624 | 0.10 | 2,857 | 27% | 0.02 | 20% |
General and administrative expense | 43,536 | 0.38 | 56,661 | 0.54 | (13,125) | (23)% | (0.16) | (30)% |
Depreciation, depletion and amortization | 103,440 | 0.91 | 92,668 | 0.89 | 10,772 | 12% | 0.02 | 2% |
(Gain) loss on oil and gas property and equipment | (36,070) | (0.32) | (62,269) | (0.60) | $26,199 | (42)% | 0.28 | (47)% |
Total operating expenses | $340,111 | $2.98 | $295,315 | $2.82 | $44,796 | 15% | $0.16 | 6% |
Lease Operating Expense (“LOE”): LOE includes costs incurred to maintain producing properties. Such costs include direct and
contract labor, repairs and maintenance, water hauling, compression, automobile, insurance, and materials and supplies expenses.
The increase in LOE was primarily driven by the acquisition of Canvas in the fourth quarter of 2025. While the total expense
increased, LOE per Mcfe remained consistent.
Production Taxes: Production taxes include severance and property taxes. Severance taxes are generally paid on produced natural
gas, NGLs and oil production at fixed rates established by federal, state, or local taxing authorities. Property taxes are generally
based on the taxing jurisdictions’ valuation of our natural gas and oil properties and midstream assets.
The increase in production taxes and production taxes per Mcfe was primarily related to an increase in severance taxes as a result of an
increase in revenue due to higher commodity prices for oil and NGLs.
Midstream Operating Expense: Midstream operating expenses are costs incurred to operate our owned midstream assets inclusive of
employee and benefit expenses.
The decrease in midstream operating expense per Mcfe was primarily related to maintaining a consistent level of midstream assets
while continuing to increase overall production for the second quarter of 2026, following the acquisition of Canvas in the fourth
quarter of 2025 and Sheridan in the second quarter of 2026. By keeping midstream operations relatively unchanged and expanding
production volumes, the per unit cost of midstream operations declined.
Transportation Expense: Transportation expenses are costs incurred from third-party systems to gather, process and transport our
natural gas, NGLs and oil.
The increase in transportation expense was driven by the Canvas acquisition in the fourth quarter of 2025. The decrease in
transportation expense per Mcfe was primarily related to additional liquids production, as transportation costs are primarily associated
with the movement of natural gas volumes.
Accretion of Asset Retirement Obligation (“Accretion”): Accretion represents the change in the carrying amount of the asset
retirement obligation over time. This expense reflects the gradual recognition of the future costs associated with retiring natural gas
and oil wells.
The increase in accretion was primarily related to the Canvas and Sheridan acquisitions in the fourth quarter of 2025 and second
quarter of 2026, respectively.
General & Administrative Expense (“G&A”): G&A includes overhead, including payroll and benefits for our corporate staff, costs of
maintaining our headquarters, costs of managing our operations, franchise taxes, audit and other professional fees, legal compliance,
equity compensation, and non-recurring costs primarily related to acquisitions.
The decrease in G&A and G&A per Mcfe was the result of significant transaction-related costs from the closing of the Maverick
acquisition in the first quarter of 2025, reflecting the full impact of the administrative synergies realized from this acquisition in 2026.
Depreciation, Depletion & Amortization Expense (“DD&A”): DD&A expenses are non-cash charges that allocate the cost of assets
and natural resources over their useful lives, reflecting their wear and tear, usage, or consumption.
The increase in DD&A was primarily related to a 9% increase in production over the period. The increase in production was due to the
Canvas and Sheridan acquisitions in the fourth quarter of 2025 and second quarter of 2026, respectively, as well as continued non-
operated development.
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Gain (Loss) on Natural Gas and Oil Properties and Equipment: Gains and (losses) on natural gas and oil properties and equipment
represent the difference between cash proceeds and recorded basis of sales of natural gas and oil properties and equipment.
The decrease in this metric was primarily related to decreased acreage sale activity, partially offset by the gain on sale recognized from
the sale of the Barnett assets. For the three months ended June 30, 2026, we recognized a gain of $24 million from acreage sales
compared to $62 million for three months ended June 30, 2025. The sale of the Barnett assets resulted in a gain of $19 million for the
three months ended June 30, 2026. Additionally, the disposal of various property, plant and equipment in the normal course of
business resulted in a loss on natural gas and oil properties and equipment of $7 million for the three months ended June 30, 2026.
Other Income (Expense)
Three Months Ended | ||||
(In thousands) | June 30, 2026 | June 30, 2025 | $ Change | % Change |
Interest expense | $(61,311) | $(56,130) | $(5,181) | 9% |
Loss on debt extinguishment | (23,882) | — | (23,882) | 100% |
Other income (expense) | 698 | 835 | (137) | (16%) |
Total other income (expense) | $(84,495) | $(55,295) | $(29,200) | 53% |
Interest Expense
Three Months Ended | ||||
(In thousands) | June 30, 2026 | June 30, 2025 | $ Change | % Change |
Interest incurred | ||||
Borrowings | $62,437 | $57,413 | $5,024 | 9% |
Other | 289 | 381 | (92) | (24)% |
Total interest incurred | 62,726 | 57,794 | 4,932 | 9% |
Less: Capitalized interest | (1,415) | (1,664) | 249 | (15)% |
Interest expense | $61,311 | $56,130 | $5,181 | 9% |
The increase in interest expense was primarily related to the issuance of the ABS XI Notes in November 2025 and the issuance of the
ABS XII Notes in May 2026. This increase was partially offset by lower outstanding balances on our existing ABS structures and
Credit Facility.
As of June 30, 2026 and December 31, 2025, total borrowings were approximately $3 billion. For the three months ended June 30,
2026, the weighted average interest rate on borrowings was 7.47% compared to 8.04% for the three months ended June 30, 2025. As
of June 30, 2026, 76% of our borrowings resided in non-recourse, fixed-rate, hedge-protected, amortizing structures compared to 71%
as of June 30, 2025.
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Loss on Debt Extinguishment
In May 2026, the proceeds from the ABS XII Notes were used to repay the outstanding principal of the ABS Maverick Notes and
ABS VI Notes, thereby retiring the ABS Maverick Notes and ABS VI Notes from the Company’s outstanding debt resulting in a loss
on the early retirement of debt of $21 million. Additionally, in June 2026, proceeds from the Barnett assets divestiture were used to
repay the outstanding principal of the ABS IV Notes, thereby retiring the ABS IV Notes from the Company’s outstanding debt and
resulting in a loss on the early retirement of debt of $2 million.
Results of Operations for the Six Months Ended June 30, 2026 Compared to the Six Months Ended June
30, 2025
Production Volumes
Six Months Ended | ||||
June 30, 2026 | June 30, 2025 | $ Change | % Change | |
Net production | ||||
Natural gas (MMcf) | 157,553 | 140,106 | 17,447 | 12% |
NGLs (MBbls) | 5,416 | 3,911 | 1,505 | 38% |
Oil (MBbls) | 5,293 | 3,121 | 2,172 | 70% |
Total production (MMcfe)(a) | 221,807 | 182,298 | 39,509 | 22% |
Average daily production (MMcfepd) | 1,225 | 1,007 | 218 | 22% |
% Natural gas (Mcfe basis) | 71% | 77% | ||
(a)The basis for converting oil and NGL volumes (MBbls) to natural gas equivalent volumes (MMcfe) is determined by using the
ratio of one Bbl of oil or NGLs to six Mcf of natural gas.
The increase in production volumes for the six months ended June 30, 2026 compared to the six months ended June 30, 2025 was
primarily related to the Maverick acquisition in the first quarter of 2025, the Canvas acquisition in the fourth quarter of 2025, and the
Sheridan acquisitions in the second quarter of 2026, as well as our continued non-operated development investment, partially offset by
normal production declines.
Commodity Pricing
The following table summarizes our average realized sales prices and benchmark prices for the periods presented:
Six Months Ended | ||||
June 30, 2026 | June 30, 2025 | $ Change | % Change | |
Average realized sales prices (before derivative settlements) | ||||
Natural gas (Mcf) | $3.04 | $3.01 | $0.03 | 1% |
NGLs (Bbls) | 27.21 | 25.76 | 1.45 | 6% |
Oil (Bbls) | 82.24 | 64.72 | 17.52 | 27% |
Total (Mcfe) | $4.78 | $3.97 | $0.81 | 20% |
Average realized sales prices (after derivative settlements) | ||||
Natural gas (Mcf) | $2.48 | $2.78 | $(0.30) | (11%) |
NGLs (Bbls) | 21.85 | 23.09 | (1.24) | (5%) |
Oil (Bbls) | 64.20 | 66.08 | (1.88) | (3%) |
Total (Mcfe) | $3.83 | $3.77 | $0.06 | 2% |
Average benchmark prices | ||||
Henry Hub (Mcf) | $3.97 | $3.55 | $0.42 | 12% |
Mont Belvieu (Bbls) | 32.35 | 38.82 | (6.47) | (17%) |
WTI (Bbls) | 82.36 | 67.58 | 14.78 | 22% |
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Commodity Revenue
The following table reconciles the change in commodity revenue (excluding the impact of derivatives settled in cash) by reflecting the
effect of changes in volume and in the underlying prices:
(In thousands) | Natural Gas | NGLs | Oil | Total |
Commodity revenue for the six months ended June 30, 2025 | $421,441 | $100,745 | $202,001 | $724,187 |
Volume increase (decrease) | 52,515 | 38,769 | 140,572 | 231,856 |
Price increase (decrease) | 4,712 | 7,864 | 92,717 | 105,293 |
Net increase (decrease) | 57,227 | 46,633 | 233,289 | 337,149 |
Commodity revenue for the six months ended June 30, 2026 | $478,668 | $147,378 | $435,290 | $1,061,336 |
The increase in commodity revenue was primarily related to the 20% increase in average realized sales prices, excluding the impact of
derivatives settled in cash, and the 22% increase in sold volumes.
Commodity Derivatives
To manage our cash flows in a volatile commodity price environment, we utilize commodity derivative contracts that enable us to
secure fixed per-unit sales prices for a portion of our production. As of June 30, 2026, approximately 86% of our production was fixed
through commodity derivative contracts over the next twelve months. The tables below set forth the impact of commodity derivatives
settlements on commodity revenue:
Six Months Ended June 30, 2026 | ||||||||
(In thousands, except per unit) | Natural Gas | NGLs | Oil | Total Commodity | ||||
Revenue | Realized $ | Revenue | Realized $ | Revenue | Realized $ | Revenue | Realized $ | |
Excluding hedge impact | $478,668 | $3.04 | $147,378 | $27.21 | $435,290 | $82.24 | $1,061,336 | $4.78 |
Gain (loss) on commodity derivatives settlements | (87,369) | (0.56) | (29,033) | (5.36) | (95,493) | (18.04) | (211,895) | (0.95) |
Including hedge impact | $391,299 | $2.48 | $118,345 | $21.85 | $339,797 | $64.20 | $849,441 | $3.83 |
Six Months Ended June 30, 2025 | ||||||||
(In thousands, except per unit) | Natural Gas | NGLs | Oil | Total Commodity | ||||
Revenue | Realized $ | Revenue | Realized $ | Revenue | Realized $ | Revenue | Realized $ | |
Excluding hedge impact | $421,441 | $3.01 | $100,745 | $25.76 | $202,001 | $64.72 | $724,187 | $3.97 |
Gain (loss) on commodity derivatives settlements | (31,437) | (0.23) | (10,440) | (2.67) | 4,223 | 1.36 | (37,654) | (0.20) |
Including hedge impact | $390,004 | $2.78 | $90,305 | $23.09 | $206,224 | $66.08 | $686,533 | $3.77 |
Gain (Loss) on Derivatives
The table below sets forth the impact of settlements and fair value adjustments on derivatives for the periods presented:
Six Months Ended | ||||
(In thousands) | June 30, 2026 | June 30, 2025 | $ Change | % Change |
Net gain (loss) on commodity derivatives settlements | $(211,895) | $(37,654) | $(174,241) | 463% |
Net gain (loss) on interest rate swaps | 37 | 70 | (33) | (47%) |
Total gain (loss) on settled derivatives(a) | $(211,858) | $(37,584) | $(174,274) | 464% |
Gain (loss) on fair value adjustments of unsettled derivatives(b) | (45,491) | (77,629) | 32,138 | (41%) |
Total gain (loss) on derivatives | $(257,349) | $(115,213) | $(142,136) | 123% |
(a)Represents the cash settlement of derivatives that were settled during the period.
(b)Represents the change in fair value of derivatives, net of the carrying value of derivatives that were settled during the period.
The change in this metric was primarily driven by a decrease in the value of settled derivatives due to increased natural gas and oil
commodity prices during the period. This decrease was partially offset by an increase in the value of unsettled derivatives during the
period based on forward commodity pricing movement.
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Operating Expenses
Six Months Ended June 30, | Total Change | Per Mcfe Change | ||||||
(In thousands, except per unit data) | 2026 | Per Mcfe | 2025 | Per Mcfe | $ | % | $ | % |
Lease operating expenses | $274,210 | $1.24 | $204,623 | $1.12 | $69,587 | 34% | $0.12 | 11% |
Production taxes | 60,151 | 0.27 | 39,750 | 0.22 | 20,401 | 51% | 0.05 | 23% |
Midstream operating expenses | 40,675 | 0.18 | 37,997 | 0.21 | 2,678 | 7% | (0.03) | (14)% |
Transportation expenses | 52,951 | 0.24 | 50,488 | 0.28 | 2,463 | 5% | (0.04) | (14)% |
Accretion of asset retirement obligation | 26,729 | 0.12 | 18,982 | 0.10 | 7,747 | 41% | 0.02 | 20% |
General and administrative expense | 85,244 | 0.38 | 90,747 | 0.50 | (5,503) | (6)% | (0.12) | (24)% |
Depreciation, depletion and amortization | 212,005 | 0.96 | 167,314 | 0.92 | 44,691 | 27% | 0.04 | 4% |
(Gain) loss on oil and gas property and equipment | (134,147) | (0.60) | (63,958) | (0.35) | $(70,189) | 110% | (0.25) | 71% |
Total operating expenses | $617,818 | $2.79 | $545,943 | $3.00 | $71,875 | 13% | $(0.21) | (7)% |
Lease Operating Expense (“LOE”): LOE includes costs incurred to maintain producing properties. Such costs include direct and
contract labor, repairs and maintenance, water hauling, compression, automobile, insurance, and materials and supplies expenses.
The increase in LOE was primarily driven by the acquisitions of Maverick in the first quarter of 2025, Canvas in the fourth quarter of
2025, and Sheridan in the second quarter of 2026. Specifically, the increase in LOE per Mcfe was primarily related to a greater
exposure to liquids production. Areas with higher liquids output tend to incur elevated operating costs, although they also benefit from
higher realized prices.
Production Taxes: Production taxes include severance and property taxes. Severance taxes are generally paid on produced natural
gas, NGLs and oil production at fixed rates established by federal, state, or local taxing authorities. Property taxes are generally
based on the taxing jurisdictions’ valuation of our natural gas and oil properties and midstream assets.
The increase in production taxes and production taxes per Mcfe was primarily related to an increase in severance and property taxes as
a result of an increase in revenue due to higher commodity prices and the additional value of added liquids revenue due to the
acquisitions discussed above, as well as additional property taxes on assets acquired.
Midstream Operating Expense: Midstream operating expenses are costs incurred to operate our owned midstream assets inclusive of
employee and benefit expenses.
The decrease in midstream operating expense per Mcfe was primarily related to maintaining a consistent level of midstream assets
while increasing overall production for the first six months of 2026, following the acquisitions of Maverick in the first quarter of 2025,
Canvas in the fourth quarter of 2025, and Sheridan in the second quarter of 2026. By keeping midstream operations relatively
unchanged and expanding production volumes, the per unit cost of midstream operations declined.
Transportation Expense: Transportation expenses are costs incurred from third-party systems to gather, process and transport our
natural gas, NGLs and oil.
The increase in transportation expense was driven by the Maverick and Canvas acquisitions in the first and fourth quarters of 2025,
respectively. The decrease in transportation expense per Mcfe was primarily related to additional liquids production, as transportation
costs are primarily associated with the movement of natural gas volumes. The Maverick and Canvas acquisitions led to an increase in
the proportion of liquids in our overall production mix.
Accretion of Asset Retirement Obligation (“Accretion”): Accretion represents the change in the carrying amount of the asset
retirement obligation over time. This expense reflects the gradual recognition of the future costs associated with retiring natural gas
and oil wells.
The increase in accretion was primarily related to the acquisitions of Maverick in the first quarter of 2025, Canvas in the fourth quarter
of 2025, and Sheridan in the second quarter of 2026.
General & Administrative Expense (“G&A”): G&A includes overhead, including payroll and benefits for our corporate staff, costs of
maintaining our headquarters, costs of managing our operations, franchise taxes, audit and other professional fees, legal compliance,
equity compensation, and non-recurring costs primarily related to acquisitions.
The decrease in G&A and G&A per Mcfe was the result of significant transaction-related costs from the closing of the Maverick
acquisition in the first quarter of 2025, in addition to recognizing administrative synergies and leveraging our existing infrastructure in
2026, which offset the acquisition-related headcount increases.
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Depreciation, Depletion & Amortization Expense (“DD&A”): DD&A expenses are non-cash charges that allocate the cost of assets
and natural resources over their useful lives, reflecting their wear and tear, usage, or consumption.
The increase in DD&A was primarily related to a 22% increase in production over the period. The increase in production was due to
the Maverick acquisition in the first quarter of 2025, the Canvas acquisition in the fourth quarter of 2025, and the Sheridan acquisition
in the second quarter of 2026, as well as continued non-operated development.
Gain (Loss) on Natural Gas and Oil Properties and Equipment: Gains and (losses) on natural gas and oil properties and equipment
represent the difference between cash proceeds and recorded basis of sales of natural gas and oil properties and equipment.
The increase in this metric was primarily related to increased acreage sales, as we strategically pursue the divestiture of select non-
core, undeveloped acreage within our operating portfolio. For the six months ended June 30, 2026, we recognized a gain of $125
million from acreage sales compared to $64 million for six months ended June 30, 2025. The sale of the Barnett assets resulted in a
gain of $19 million for the six months ended June 30, 2026. Additionally, the disposal of various wells and property, plant and
equipment in the normal course of business resulted in a loss on natural gas and oil properties and equipment of $10 million for the six
months ended June 30, 2026.
Other Income (Expense)
Six Months Ended | ||||
(In thousands) | June 30, 2026 | June 30, 2025 | $ Change | % Change |
Interest expense | (124,723) | (98,842) | (25,881) | 26% |
Loss on debt extinguishment | (23,882) | (26,971) | 3,089 | (11%) |
Other income (expense) | 1,246 | 1,103 | 143 | 13% |
Total other income (expense) | $(147,359) | $(124,710) | $(22,649) | 18% |
Interest Expense
Six Months Ended | ||||
(In thousands) | June 30, 2026 | June 30, 2025 | $ Change | % Change |
Interest incurred | ||||
Borrowings | $125,944 | $100,107 | $25,837 | 26% |
Other | 1,030 | 625 | 405 | 65% |
Total interest incurred | 126,974 | 100,732 | 26,242 | 26% |
Less: Capitalized interest | (2,251) | (1,890) | (361) | 19% |
Interest expense | $124,723 | $98,842 | $25,881 | 26% |
The increase in interest expense was primarily related to the issuance of the ABS X Notes in February 2025, the assumption of the
ABS Maverick Notes as a result of the Maverick acquisition in March 2025, the issuance of the Nordic Bonds in April 2025, the
issuance of the ABS XI Notes as a result of the Canvas acquisition in November 2025, and the issuance of the ABS XII Notes in May
2026. This increase was partially offset by lower outstanding balances on our existing ABS structures and Credit Facility.
As of June 30, 2026 and December 31, 2025, total borrowings were $3 billion, respectively. For the six months ended June 30, 2026,
the weighted average interest rate on borrowings was 7.58% compared to 7.82% for the six months ended June 30, 2025. As of June
30, 2026, 76% of our borrowings resided in non-recourse, fixed-rate, hedge-protected, amortizing structures compared to 71% as of
June 30, 2025.
Loss on Debt Extinguishment
In February 2025, the proceeds from the ABS X Notes were used to repay the outstanding principal of the ABS I & II Notes and Term
Loan I, retiring these from our outstanding debt and resulting in a loss on debt extinguishment of $27 million.
In May 2026, the proceeds from the ABS XII Notes were used to repay the outstanding principal of the ABS Maverick Notes and
ABS VI Notes, thereby retiring the ABS Maverick Notes and ABS VI Notes from the Company’s outstanding debt resulting in a loss
on the early retirement of debt of $21 million. Additionally, in June 2026, proceeds from the Barnett assets divestiture were used to
repay the outstanding principal of the ABS IV Notes, thereby retiring the ABS IV Notes from the Company’s outstanding debt and
resulting in a loss on the early retirement of debt of $2 million.
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Income Tax Benefit (Expense)
The effective tax rates can be materially impacted by the recognition of the marginal well tax credit available to qualified producers as
reflected in our effective tax rates for the six months ended June 30, 2026 and 2025. The federal government provides these credits to
incentivize companies to continue operating lower-output wells during periods of low prices. This support helps sustain production,
preserve the jobs associated with these operations, and ensures that communities continue to receive state and local tax income. Such
revenue is vital for funding schools, law enforcement, social initiatives, and other essential public services.
The provision for income taxes in the Condensed Consolidated Statements of Comprehensive Income (Loss) is summarized below:
Six Months Ended | ||||
(In thousands) | June 30, 2026 | June 30, 2025 | $ Change | % Change |
Income (loss) before taxation | $73,875 | $(21,441) | $95,316 | (445)% |
Income tax benefit (expense) | 13,065 | (3,464) | 16,529 | (477)% |
Effective tax rate | (17.7)% | (16.2)% | ||
Tax benefit for the six months ended June 30, 2026 represented a favorable change compared to an expense for the six months ended
June 30, 2025. The change was primarily driven by the movement in income (loss) before taxation and the recognition of marginal
well credits.
Liquidity and Capital Resources
Overview
Our primary sources of liquidity are cash generated from operating activities and available capacity under our Credit Facility. As of
June 30, 2026, we had approximately $678 million of liquidity, consisting of $8 million of cash on hand and $669 million of
availability under our Credit Facility.
When we acquire producing assets, we typically complement our Credit Facility with long-term, fixed-rate, amortizing, asset-backed
debt secured by certain natural gas and oil assets. This asset-backed debt is non-recourse to the Company. Our financing strategy is
designed to align with the long-life nature of our assets, provide access to lower-cost capital and support a clear path to leverage
reduction through scheduled principal payments. For larger acquisitions requiring greater capital outlays, we have raised, and may in
the future raise, additional capital through equity offerings to maintain an appropriate leverage profile.
We closely monitor our working capital to ensure it remains sufficient to support our strategic initiatives, business operations,
dividend payments to shareholders and repurchases of common stock. In addition, we maintain a disciplined approach to managing
operating costs and allocating capital resources, with a focus on investments that support our objectives and generate appropriate
returns.
Capital expenditures were $98 million for the six months ended June 30, 2026, compared to $89 million for the six months ended June
30, 2025. The increase in capital expenditures was primarily related to the development of new wells via a non-operated development
agreement that came with the undeveloped locations acquired in the Maverick acquisition. We expect to meet our capital expenditure
needs for the foreseeable future through cash flows from operations and existing liquidity. Our future capital requirements will depend
on several factors, including scope of development activities, the pace of our growth, commodity price fluctuations, and future
acquisitions.
The majority of our current capital expenditures are directed toward upstream and midstream operations, including pipelines and
compression. The remaining expenditures are focused on production optimization, technology, plugging requirements, fleet, emissions
reduction initiatives and development activities.
Looking ahead, we intend to support stable cash flows by maintaining our hedging strategy and capitalizing on market opportunities to
enhance the hedged commodity prices of our production. We also plan to preserve our strategic advantages through purposeful
growth, supported by a disciplined capital expenditure program. We believe this approach will help us maintain access to low-cost
financing for acquisitive growth while preserving appropriate leverage and sufficient liquidity.
With respect to other known current obligations, we believe our sources of liquidity and capital resources will be sufficient to meet our
existing business needs for at least the next 12 months. However, our ability to satisfy working capital requirements, debt service
obligations, and planned capital expenditures, as well as our ability to pay dividends, will depend on our future operating performance.
Our future operating performance will be affected by prevailing economic conditions in the natural gas and oil industry, along with
other financial and business factors, some of which are beyond our control.
For additional information regarding borrowings and debt covenants, refer to Note 10 in the Notes to the Condensed Consolidated
Financial Statements.
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Liquidity
As of | ||
(In thousands) | June 30, 2026 | December 31, 2025 |
Cash and cash equivalents | $8,238 | $29,697 |
Available borrowings under the Credit Facility(a) | 669,322 | 304,912 |
Liquidity | $677,560 | $334,609 |
(a)Represents available borrowings under the Credit Facility of $705 million as of June 30, 2026 less outstanding letters of credit of
$35 million as of such date. Represents available borrowings under the Credit Facility of $340 million as of December 31, 2025
less outstanding letters of credit of $35 million as of such date.
Cash Flows
Six Months Ended | ||||
(In thousands) | June 30, 2026 | June 30, 2025 | $ Change | % Change |
Net cash provided by operating activities | $257,516 | $165,138 | $92,378 | 56% |
Net cash (used in) investing activities | (101,506) | (395,870) | 294,364 | (74%) |
Net cash (used in) provided by financing activities | (197,735) | 305,374 | (503,109) | (165%) |
Net change in cash, cash equivalents and restricted cash | $(41,725) | $74,642 | $(116,367) | (156%) |
Net Cash Provided by Operating Activities
The change in operating activities was primarily related to increased revenues as a result of increased liquids pricing and production
stemming from the Maverick acquisition in the first quarter of 2025, the Canvas acquisition in the fourth quarter of 2025, and the
Sheridan acquisition in the second quarter of 2026, as well as our continued non-operated development investment and higher liquids
commodity pricing.
Net Cash (Used in) Investing Activities
The change in investing activities was primarily related to decreased acquisition activity in 2026, which included the Sheridan
acquisition, as compared to the same period in 2025, which included the Summit and Maverick acquisitions. Additionally, we received
increased cash proceeds from the sale of the Barnett assets and undeveloped acreage during the six months ended June 30, 2026.
Net Cash (Used in) Provided by Financing Activities
The change in financing activities was primarily related to a decrease in borrowing activity in 2026, when we received proceeds from
the tap-on offering of Nordic Bonds and the issuance of the ABS XII Notes, as compared to 2025, when we received proceeds from
the issuance of the ABS X Notes as well as our equity offering, partially offset by hedge modification payments and deferred
financing costs incurred in connection with the ABS X transaction. Additionally, during 2026, we increased share repurchases as part
of our stock repurchase program as compared to 2025.
Off-Balance Sheet Arrangements
We may enter into off-balance sheet arrangements and transactions that give rise to material off-balance sheet obligations. As of June
30, 2026, our material off-balance sheet arrangements and transactions include operating service contractual obligations of $295
million and letters of credit outstanding against our Credit Facility of $35 million. Refer to Contractual Obligations for additional
information.
As of June 30, 2026, there are no other transactions, arrangements or other relationships with unconsolidated entities or other persons
that are reasonably likely to materially affect our liquidity or availability of capital resources.
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Contractual Obligations
We have various contractual obligations in the normal course of our operations and financing activities. Significant contractual
obligations as of June 30, 2026 were as follows:
(In thousands) | Remainder of 2026 | 2027 | 2028 | 2029 | 2030 | Thereafter | Total |
Recorded contractual obligations | |||||||
Accounts payable | $129,539 | $— | $— | $— | $— | $— | $129,539 |
Accrued liabilities | 166,485 | — | — | — | — | — | 166,485 |
Borrowings(a) | 66,171 | 97,462 | 91,520 | 784,535 | 163,172 | 1,775,869 | 2,978,729 |
Operating leases | 5,945 | 10,069 | 8,931 | 3,750 | 2,663 | 510 | 31,868 |
Finance leases | 12,254 | 23,150 | 19,519 | 13,691 | 6,308 | 1,240 | 76,162 |
Asset retirement obligation(b) | 13,559 | 29,035 | 26,365 | 51,191 | 19,484 | 3,503,668 | 3,643,302 |
Other liabilities(c) | 88,219 | 28,770 | — | — | — | — | 116,989 |
Off-Balance Sheet contractual obligations | |||||||
Firm transportation(d) | 15,286 | 21,131 | 15,476 | 11,237 | 5,050 | 226,888 | 295,068 |
Total contractual obligations | $497,458 | $209,617 | $161,811 | $864,404 | $196,677 | $5,508,175 | $7,438,142 |
(a)The future maturities presented reflect scheduled principal amortization under the terms of each instrument and does not reflect
the effect of the anticipated repayment dates of the ABS Notes, which occur between May 2029 and May 2031.
(b)Represents our asset retirement obligation on an undiscounted basis. On a discounted basis the liability is $906 million as of June
30, 2026 as presented in the Consolidated Balance Sheets.
(c)Represents taxes payable, deferred tax liability, noncurrent derivative liabilities, and other current and noncurrent liabilities.
(d)Represents reserved capacity to transport gas from production locations through pipelines to the ultimate sales meters.
For more detailed information on asset retirement obligations and borrowings refer to Notes 9 and 10 within the Notes to the
Condensed Consolidated Financial Statements.
Litigation and Regulatory Proceedings & Environmental Matters
For Information regarding legal proceedings and environmental matters, refer to Note 12 to the Notes to the Condensed Consolidated
Financial Statements.
Critical Accounting Estimates
There have been no material changes to the Company’s critical accounting estimates from those disclosed in the Company’s Annual
Report on Form 10-K for the year ended December 31, 2025.
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Item 3. Quantitative and Qualitative Disclosures About Market Risk
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our
potential exposure to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in natural gas, NGLs
and oil prices, as well as interest rates. These disclosures are not meant to be precise indicators of expected future losses, but rather
indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our
ongoing market risk exposures.
Commodity Price Risk
Our revenues are primarily derived from the sale of natural gas, NGLs, and oil production, subjecting us to commodity price risk.
Commodity prices for natural gas, NGLs and oil can be volatile and may fluctuate due to relatively small changes in supply, weather
conditions, economic conditions, and government actions. For the six months ended June 30, 2026, our natural gas, NGLs, and oil
revenue was $479 million, $147 million, and $435 million, respectively. Based on production, natural gas, NGLs and oil revenue for
the six months ended June 30, 2026 would have increased or decreased by approximately $48 million, $15 million, and $44 million,
respectively, for each 10% increase or decrease in prices.
To mitigate the risk of fluctuations in commodity prices, we enter into derivatives. The total volumes hedged through the use of these
instruments vary from period to period. Generally our objective is to hedge approximately 60% to 80% of anticipated production
volumes for the next 12 months, at least 50% for months 13 to 24, and a minimum of 30% for months 25 to 36. For additional
information regarding derivatives, refer to Note 6 in the Notes to the Condensed Consolidated Financial Statements.
By removing price volatility from a significant portion of our expected production through 2028, we have mitigated, but not
eliminated, the potential effects of changing prices on operating cash flow for those periods. While these derivative contracts help
mitigate the negative effects of falling commodity prices, they also limit the benefits we would receive from increases in commodity
prices.
As of June 30, 2026, the fair value of our natural gas derivatives was a net liability of $289 million, NGLs derivatives were in a net
liability position of $44 million, and our oil derivatives were in a net liability position of $63 million. For the six months ended June
30, 2026, a 10% fluctuation in commodity prices would have a corresponding impact of approximately $29 million, $4 million, and $6
million on natural gas, NGLs and oil derivatives, respectively.
Interest Rate Risk
We are subject to market risk exposure related to changes in interest rates. Our borrowings primarily consist of fixed-rate amortizing
notes and a variable rate Credit Facility as illustrated below.
As of June 30, 2026 | ||
(in thousands) | Borrowings | Interest Rate(a) |
ABS Notes, Nordic Bonds, & other(b) | $2,783,429 | 7.68% |
Credit Facility | $195,300 | 6.88% |
(a)The interest rate on the ABS Notes, Nordic Bonds, and other notes payable represents the weighted average fixed rate of the
notes, while the interest rate presented for the Credit Facility represents the floating rate as of June 30, 2026.
(b)Includes $20 million in notes payable issued by a third party financial institution in November 2024 collateralized by two natural
gas processing plants and various natural gas compressors and related support equipment in the Central Region, as of June 30,
2026.
For additional information regarding the Company’s borrowings, refer to Note 10 in the Notes to the Condensed Consolidated
Financial Statements.
For the six months ended June 30, 2026, a 100 basis point adjustment in the borrowing rate for the Credit Facility would result in a
corresponding annual effect on interest expense of approximately $2 million. This represents a reasonably possible change in interest
rate risk.
We strive to maintain a prudent balance of floating and fixed-rate borrowing exposure, particularly during uncertain market
conditions. As part of our risk mitigation strategy, we occasionally enter into swap arrangements to adjust our exposure to floating or
fixed interest rates, depending on changes in the composition of borrowings in our portfolio. Consequently, the total principal hedged
through the use of derivatives varies from period to period.
As of June 30, 2026, the fair value of our interest rate swaps represents an asset of $0.1 million. For additional information regarding
derivatives, refer to Note 6 in the Notes to the Condensed Consolidated Financial Statements.
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Counterparty & Customer Credit Risk
We are exposed to counterparty and customer credit risk from the hedging and sale of our natural gas, NGLs and oil.
Our derivative instruments expose us to our counterparties’ credit risk. To mitigate this risk, we only enter into commodity contracts
with counterparties that are creditworthy financial institutions deemed by us to have acceptable credit strength and competence.
Counterparty non-performance risk is considered in the valuation of our derivative instruments, but has not had an impact on the value
of our derivatives. We also attempt to limit our exposure to non-performance by any single counterparty. As of June 30, 2026, our
commodity contracts and derivative instruments were spread among 14 counterparties.
For additional information regarding derivatives, refer to Note 6 in the Notes to the Condensed Consolidated Financial Statements.
Accounts receivable from customers represent amounts due for the purchase of these commodities, and their collectability depends on
the financial condition of each customer. We review the financial condition of customers before extending credit and generally do not
require collateral to support their accounts receivable. As of June 30, 2026, we had no customer that comprised over 10% of our total
accounts receivable from customers. Net of the applicable allowance for credit losses, our accounts receivable from customers were
$343 million as of June 30, 2026.
The Company is also exposed to credit risk from joint interest owners, which are entities that own a working interest in the properties
operated by the Company. Joint interest receivables are classified under accounts receivable, net, in the Condensed Consolidated
Balance Sheets. The Company has the ability to withhold future revenue payments to recover any non-payment of joint interest
receivables. As of June 30, 2026, our joint interest receivables, net of the applicable allowance for credit losses, were $65 million.
Accounts receivable are current, and the Company believes these net receivables are collectible.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
The Company maintains disclosure controls and procedures, as defined in U.S. Securities Exchange Act of 1934, as amended
(“Exchange Act”) Rule 13a-15(e), that are designed to ensure that information required to be disclosed in our reports filed or
submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and
forms of the SEC, and such information 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. The Chief Executive Officer and
Chief Financial Officer, with the participation of management, have evaluated the effectiveness of the Company’s disclosure controls
and procedures in relation to Exchange Act Rule 13a-15(b), and have concluded that the Company’s disclosure controls and
procedures were effective as of June 30, 2026.
Changes in Internal Controls Over Financial Reporting
There were no changes in our internal control over financial reporting during the quarter ended June 30, 2026, which materially
affected, or were reasonably likely to materially affect, our internal control over financial reporting.
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PART II - OTHER INFORMATION
Item 1. Legal Proceedings
We are a party to various routine legal proceedings, disputes and claims arising in the ordinary course of our business, including those
that arise from the interpretation of federal and state laws and regulations affecting the crude oil and natural gas exploration and
development industry, personal injury claims, title disputes, royalty disputes, contract claims, contamination claims relating to crude
oil and natural gas exploration and development and environmental claims, including claims involving assets previously sold to third
parties and no longer part of our current operations. While the ultimate outcome of the pending proceedings, disputes or claims, and
any resulting impact on us, cannot be predicted with certainty, we believe that none of these matters, if ultimately decided adversely,
will have a material adverse effect on our financial condition, results of operations or cash flows.
In April 2023, the Department of Environmental Protection for the Commonwealth of Pennsylvania issued an administrative order to
our subsidiary with respect to certain above ground facilities. We have completed the remedial actions required by the order and the
Commonwealth of Pennsylvania has proposed a civil penalty of approximately $1.9 million, which the Company is reviewing and
engaging with the Department on.
Except as provided above, there have been no material developments with respect to the information previously reported under Part I,
Item 3. “Legal Proceedings” of our Annual Report on Form 10-K for the year ended December 31, 2025.
Item 1A. Risk Factors
There have been no material changes to the Company’s “Risk Factors” previously disclosed in Part I, Item 1A of our Annual Report
on Form 10-K for the year ended December 31, 2025, except as provided below.
We have limited historical experience as an operator of development programs.
We have initiated an operated development program which will require us to devote additional financial, technical and operational
resources to drilling and completion activities. Development activities generally require us to commit capital substantially in advance
of realizing production and cash flows, which may increase the variability of returns compared to our historical acquisition strategy.
Although we have drilled wells in various basins in the past and we have highly skilled personnel with significant drilling and
completion experience through prior acquisitions, including our Chief Operating Officer, who previously oversaw the drilling program
at Maverick Natural Resources, our historical business model has primarily focused on the acquisition, optimization and operation of
existing producing assets.
Success in development programs depends upon effective well planning, capital allocation, execution of drilling and completion
operations, reservoir evaluation, leasing, permitting, and project management. Executing these operations will require us to engage
and rely upon drilling contractors, completion crews and other oilfield services providers, whose availability, performance and pricing
are outside our control. Our development activities may not achieve expected results, and our returns could be adversely affected if
development costs increase, reserve estimates are revised downward, or wells fail to perform as anticipated. In addition, we cannot
provide assurance that unproved property acquired by us will be profitably developed, that wells drilled in connection with our
development activities will be productive, or that we will recover all or any portion of our investment in such unproved property or
wells.
Our development activities are subject to risks and uncertainties that are not present, or are present to a lesser degree, in our
existing producing asset base.
Historically, a substantial portion of our business has consisted of acquiring and operating existing producing assets. As we increase
our investment in drilling and development activities, we are exposed to additional risks, including:
•dry holes, or wells that are productive but do not produce sufficient volumes to recover drilling and completion and operating
costs, or to achieve targeted returns;
•drilling or completion delays, or the curtailment or cancellation of planned activity;
•cost overruns and increases in drilling and completion costs;
•shortages of or delays in obtaining qualified personnel or equipment, including rigs, pressure pumping crews, tubulars, sand,
water, chemicals and other equipment or critical services;
•unexpected geological conditions;
•drilling hazards and mechanical failures;
•well control incidents, blowouts, fires and environmental events;
•leasing or title problems;
•delays in obtaining permits and regulatory approvals, and environmental, health and safety requirements applicable to drilling
and completion operations;
•adverse weather and surface access constraints;
•inability to secure or dispose of water used in drilling and completion operations; and
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•insufficient takeaway, gathering or processing capacity.
Any of these events may result in increases in costs, delays in production, lower-than-expected recoveries, impairment of capital
invested in development projects and reduced returns.
Estimates of reserves, drilling inventory and future development opportunities are inherently uncertain and may prove to be
inaccurate.
The identification of drilling locations and estimates of reserves, estimated ultimate recovery, production profiles and future economic
returns depend upon complex geological, geophysical, engineering and economic analyses. These analyses require assumptions
regarding reservoir characteristics, hydrocarbon recovery, well performance, commodity prices, capital costs and operating expenses.
In evaluating undeveloped acreage, we may rely on seismic data, well logs, core information, production data from offset operators,
geologic models, type curves and other technical information. The interpretation of such information is inherently uncertain.
Actual drilling results may differ materially from our expectations. Wells that we believe are commercially attractive based on seismic
interpretation or geologic analysis may fail to achieve anticipated production rates, recoveries or economic returns. New information
obtained through drilling and production activities may require us to revise reserve estimates, development plans, drilling inventories
and expected future cash flows.
Because drilling and completion occurs over an extended period, the economics of our development activities are subject to changes in
commodity prices between the time we commit capital and the time any resulting production is sold. If we are unable to execute
drilling and completion programs successfully, such failure could materially and adversely affect our business, results of operations,
and financial condition.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Repurchases of Common Stock
Following are our monthly share repurchases of common stock for the quarter ended June 30, 2026:
Period | Total Number of Shares Purchased | Average Price Paid Per Share | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | Maximum Number of Shares That May Yet Be Purchased Under the Plans or Programs |
April | — | $— | — | 2,766,636 |
May | — | $— | — | 2,766,636 |
June | 944,887 | $13.43 | 944,887 | 1,821,749 |
Total | 944,887 | $13.43 | 944,887 |
All repurchases of common stock were made using cash on hand and liquidity at the time of purchase. Our repurchases of common
stock may occur through open market purchases, private transactions, or pursuant to a Rule 10b5-1 trading plan.
On February 25, 2026, the Board approved a stock repurchase program (the “2026 Repurchase Program”) authorizing the Company to
repurchase up to 7,800,000 shares. The 2026 Repurchase Program authorizes the repurchase of common stock through March 1, 2027.
Repurchases of common stock under the program may be made, from time to time, in privately negotiated transactions, in open market
transactions, or by other means, including through trading plans intended to qualify under Rule 10b-18 and/or Rule 10b5-1 of the U.S.
Securities Exchange Act of 1934, as amended. The amount and timing of any repurchases made under the program will be in the
Company’s sole discretion and will depend on a variety of factors, including legal requirements, market conditions, other investment
opportunities, available liquidity, and the prevailing market price of the common stock. The program does not obligate the Company
to repurchase any dollar amount or number of shares of common stock, and the program may be suspended or discontinued at any
time at the Company’s discretion.
Item 3. Defaults Upon Senior Securities
None.
Item 4. Mine Safety Disclosures
None.
Item 5. Other Information
During the three months ended June 30, 2026, no director or officer of the Company adopted terminated
arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408 of Regulation S-K.
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Item 6. Exhibits
Exhibit No. | Incorporated by reference | Filed | Furnished | ||||
Description | Form | Exhibit | Filing Date | Herewith | Only | ||
2.1 | † | Securities Purchase Agreement dated May 6, 2026, by and among Camino Natural Resources, LLC, Camino Natural Resources Intermediate HoldCo, LLC, Land Run Minerals II, LLC, the other sellers named therein and Diversified Gas & Oil Corporation | 8-K File No. 001-41870 | 2.1 | 5/12/2026 | ||
3.1 | Amended and Restated Certificate of Incorporation of Diversified Energy Company | 8-K File No. 001-41870 | 3.1 | 11/24/2025 | |||
3.2 | Amended and Restated Bylaws of Diversified Energy Company | 8-K File No. 001-41870 | 3.2 | 11/24/2025 | |||
4.1 | † | Base Indenture dated May 13, 2026, by and among DP Red River LLC, as Issuer, Diversified ABS VI Upstream LLC, Oaktree ABS VI Upstream LLC, MNR ABS Issuer I, LLC, and MNR ABS Agent Corp, as Guarantors, and UMB Bank, N.A., as Indenture Trustee and Securities Intermediary | 8-K File No. 001-41870 | 4.1 | 5/19/2026 | ||
4.2 | † | Series 2026-1 Supplement dated May 13, 2026, by and among DP Red River LLC, as Issuer, Diversified ABS VI Upstream LLC, Oaktree ABS VI Upstream LLC, MNR ABS Issuer I, LLC, and MNR ABS Agent Corp, as Guarantors, and UMB Bank, N.A., as Indenture Trustee | 8-K File No. 001-41870 | 4.2 | 5/19/2026 | ||
10.1 | † | Third Amendment to Second Amended and Restated Revolving Credit Agreement dated as of April 30, 2026 | ü | ||||
31.1 | Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | ü | |||||
31.2 | Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | ü | |||||
32.1 | Certification of the Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes- Oxley Act of 2002 | ü | |||||
101 | Interactive Data File. The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. | ||||||
104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) | ||||||
† | Certain schedules and attachments have been omitted. The registrant hereby undertakes to provide further information regarding such omitted materials to the Securities and Exchange Commission upon request. |
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Signatures
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.
Dated: August 5, 2026
DIVERSIFIED ENERGY COMPANY | |||
(Registrant) | |||
/s/ Bradley G. Gray | |||
Bradley G. Gray | |||
President and Chief Financial Officer | |||