Phoenix Energy One posts $1.4M Q3 net loss
Nine-month operating cash flow was $489.0 million, alongside a $265.0 million derivative loss and a current-ratio covenant waiver.
Sentiment and the balance of points
Rhea-AI Sentiment reads the wording of the document, how positive or negative its language is on a 1 to 5 scale. The balance of points shown with the takes weighs what the document actually discloses, so the two can disagree, for example when a trial that missed its main goal is described in upbeat language.
Rhea-AI Filing Summary
Phoenix Energy One, LLC (PHXE) reported third-quarter revenue of $460.4 million, versus $189.0 million in 2025. Operating income was $148.4 million, compared with $46.3 million, while an $87.8 million derivative loss (versus a $2.1 million gain) accompanied a $1.4 million net loss; the prior-year quarter had $8.5 million net income. Nine-month revenue was $1,164.9 million versus $468.6 million, and net loss was $35.5 million versus $32.8 million net income.
Nine-month operating cash flow was $489.0 million, compared with $204.7 million in 2025. Investing activities used $848.6 million, including $850.4 million of additions to oil and gas properties; financing provided $407.7 million, including $536.7 million in net debt issuance proceeds and $56.1 million in debt repayments. Nine-month derivative results were a $265.0 million loss, versus a $12.9 million gain.
As of September 30, 2026, outstanding debt was $2,030.6 million and working capital was negative $487.1 million. After quarter-end, the company raised $84.8 million of notes and said it had sufficient financial resources to operate beyond the next 12 months following issuance of the statements. On October 21, it obtained a waiver of current-ratio covenant noncompliance for the month ended September 30.
How this balance works
Rhea-AI gives every point it takes from this document a weight. Minor counts 1, Moderate 3 and Major 9, so one Major point outweighs several Minor ones. The bar adds up the weights on each side, and when neither side holds more than 65% of the total the balance reads Mixed.
It reads the document as published, with the same rules for every company, and it does not look at what the market expected or at how the stock traded, so a point can be objectively good on a day the stock falls.
Rhea-AI Sentiment measures something else, the tone of the wording.
Positive
- Moderate pointNine-month revenue was $1,164.9 million, versus $468.6 million in 2025.
- Moderate pointNine-month operating cash flow was $489.0 million, versus $204.7 million in 2025.
Negative
- Major pointNine-month derivative results were a $265.0 million loss, versus a $12.9 million gain.
- Moderate pointNine-month net loss was $35.5 million, versus $32.8 million net income in 2025.
- Moderate pointCurrent-ratio covenant noncompliance for the month ended September 30, 2026 received a waiver.
Filing Explained
The gas contract sets a five-year, 20-million-Mcf minimum beginning March 2027, with infrastructure payments scheduled through milestone-based installments.
Under the active 15-year gas gathering and processing contract,
The company committed
The filing also lists Phoenix Flex Notes as outstanding debt secured by junior liens on certain properties, behind the Fortress Credit Agreement’s first lien.
Subject to subordination, holders may request repayment at scheduled put dates for principal plus accrued interest, or request redemption before maturity at 95% of principal, subject to a 10% annual limit.
Key Figures
Key Terms
successful efforts method financial
Two-Way Collars financial
Loan-to-Value Ratio financial
Level 2 financial
FAQ
AI-generated questions and answers. How Rhea-AI works. Not financial advice.
What revenue did PHXE report in the third quarter of 2026?
Did PHXE make a profit in the third quarter of 2026?
How much debt did PHXE have as of September 30, 2026?
Why did PHXE receive a current-ratio covenant waiver?
AI-generated analysis. How Rhea-AI works. Not financial advice.
Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM
(Mark One)
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from ____________ to ____________
Commission File Number:
(Exact Name of Registrant as Specified in its Charter)
(State or other jurisdiction of incorporation or organization) |
(I.R.S. Employer |
(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 |
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Trading Symbol(s) |
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Name of each exchange on which registered |
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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.
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer |
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Accelerated filer |
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Emerging growth company |
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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
As of November 9, 2026, there were
Table of Contents
Table of Contents
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Page |
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PART I. |
FINANCIAL INFORMATION |
5 |
Item 1. |
Financial Statements (Unaudited) |
5 |
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Condensed Consolidated Balance Sheets |
5 |
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Condensed Consolidated Statements of Operations |
6 |
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Condensed Consolidated Statements of Changes in Equity (Deficit) |
7 |
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Condensed Consolidated Statements of Cash Flows |
8 |
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Notes to the Condensed Consolidated Financial Statements |
9 |
Item 2. |
Management’s Discussion and Analysis of Financial Condition and Results of Operations |
26 |
Item 3. |
Quantitative and Qualitative Disclosures About Market Risk |
48 |
Item 4. |
Controls and Procedures |
51 |
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PART II. |
OTHER INFORMATION |
52 |
Item 1. |
Legal Proceedings |
52 |
Item 1A. |
Risk Factors |
52 |
Item 2. |
Unregistered Sales of Equity Securities and Use of Proceeds |
52 |
Item 3. |
Defaults Upon Senior Securities |
52 |
Item 4. |
Mine Safety Disclosures |
52 |
Item 5. |
Other Information |
52 |
Item 6. |
Exhibits |
60 |
SIGNATURES |
62 |
|
i
Table of Contents
Certain Defined Terms
As used in this Quarterly Report on Form 10-Q (this “Quarterly Report”), unless otherwise noted or the context otherwise requires, references to:
1
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2
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For ease of reference, we have repeated definitions for certain of these terms in other portions of the body of this Quarterly Report. All such definitions conform to the definitions set forth above.
Certain monetary amounts, percentages, and other figures included in this Quarterly Report have been subject to rounding adjustments. Percentage amounts included in this Quarterly Report have not in all cases been calculated on the basis of such rounded figures, but on the basis of such amounts prior to rounding. For this reason, percentage amounts in this Quarterly Report may vary from those obtained by performing the same calculations using the figures on our condensed consolidated financial statements included elsewhere in this Quarterly Report. Certain other amounts that appear in this Quarterly Report may not sum due to rounding.
Cautionary Statement Regarding Forward-Looking Statements
This Quarterly Report contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, which are statements regarding all matters that are not historical facts. They appear in a number of places throughout this Quarterly Report and our 2025 Annual Report and include statements regarding our current views, hopes, intentions, beliefs, or expectations concerning, among other things, our results of operations, financial condition, liquidity, prospects, growth, strategies, and position in the markets and the industries in which we operate. These forward-looking statements are generally identifiable by forward-looking terminology such as “guidance,” “expect,” “believe,” “anticipate,” “outlook,” “could,” “target,” “project,” “intend,” “plan,” “seek,” “estimate,” “should,” “will,” “would,” “approximately,” “predict,” “potential,” “may,” “continue,” and “assume,” as well as the negative version of such words, variations of such words, and similar expressions referring to the future.
Forward-looking statements are based on our beliefs, assumptions, and expectations, taking into account currently known market conditions and other factors. Our ability to predict results or the actual effect of future events, actions, plans, or strategies is inherently uncertain and involves certain risks and uncertainties, many of which are beyond our control. Our actual results and performance could differ materially from those set forth or anticipated in our forward-looking statements. Factors that could cause our actual results to differ materially from the expectations we describe in our forward-looking statements include, but are not limited to, the factors listed below and in the section of our 2025 Annual Report entitled “Risk Factors.” When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Quarterly Report. You are cautioned that the forward-looking statements contained in this Quarterly Report are not guarantees of future performance, and we cannot assure you that such statements will be realized or that the forward-looking events and circumstances will occur. All forward-looking statements in this Quarterly Report are made only as of the date of this Quarterly Report, based on information available to us as of the date of this Quarterly Report, and we caution you not to place undue reliance on forward-looking statements in light of the risks and uncertainties associated with them.
The matters summarized below and elsewhere in this Quarterly Report could cause our actual results and performance to differ materially from those set forth or anticipated in forward-looking statements:
3
Table of Contents
Except as required by law, we are under no duty to, and we do not intend to, update or review any of our forward-looking statements after the date of this Quarterly Report, whether as a result of new information, future events or developments, or otherwise.
Investors and others should note that we announce financial and other material information using our website (https://phoenixenergy.com/), SEC filings, press releases, public conference calls, and webcasts. We use these channels of distribution to communicate with our investors and members of the public about the Company, our products and services, and other items of interest. Information contained on our website is not part of this Quarterly Report or our other filings with the SEC.
4
Table of Contents
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements (Unaudited)
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Condensed Consolidated Balance Sheets
(in thousands, except share amounts)
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September 30, |
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December 31, |
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(unaudited) |
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ASSETS |
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Current assets |
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Cash and cash equivalents |
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$ |
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$ |
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Accounts receivable |
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Accounts receivable—related party |
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Earnest payments |
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Current derivative assets |
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Other current assets |
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Total current assets |
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Property, plant, and equipment |
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Oil and gas properties |
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Other property and equipment |
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Less: accumulated depreciation, depletion, and amortization |
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Total property, plant, and equipment, net |
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Right-of-use assets, net |
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Noncurrent derivative assets |
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Other noncurrent assets |
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TOTAL ASSETS |
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$ |
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$ |
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LIABILITIES AND EQUITY |
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Current liabilities |
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Accounts payable |
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$ |
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$ |
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Accrued expenses |
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Current portion of long-term debt |
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Current portion of deferred closings |
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Escrow account |
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Current operating lease liabilities |
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Current derivative liabilities |
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Other current liabilities |
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Total current liabilities |
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Long-term debt, net of current portion |
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Accrued interest |
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Deferred closings |
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Operating lease liabilities |
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Asset retirement obligations |
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Noncurrent derivative liabilities |
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Other noncurrent liabilities |
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Total liabilities |
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Equity |
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Series A Preferred Shares ( |
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Common equity |
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Retained earnings (accumulated deficit) |
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( |
) |
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Total equity |
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TOTAL LIABILITIES AND EQUITY |
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$ |
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$ |
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The accompanying notes are an integral part of these condensed consolidated financial statements.
5
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Condensed Consolidated Statements of Operations
(unaudited)
(in thousands)
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Three Months Ended |
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Nine Months Ended |
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2026 |
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2025 |
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2026 |
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2025 |
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REVENUES |
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Product sales |
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$ |
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$ |
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$ |
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$ |
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Mineral and royalty revenues |
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Purchased crude oil sales |
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Water services |
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Other revenue |
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Total revenues |
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OPERATING EXPENSES |
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Cost of sales |
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Depreciation, depletion, and amortization |
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Purchased crude oil expenses |
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Selling, general, and administrative |
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Payroll and payroll-related |
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Advertising and marketing |
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Gain on sale of assets |
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( |
) |
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( |
) |
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Impairment expense |
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Total operating expenses |
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INCOME FROM OPERATIONS |
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OTHER INCOME (EXPENSE) |
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Interest income |
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Interest expense, net |
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( |
) |
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( |
) |
|
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( |
) |
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( |
) |
Gain (loss) on derivatives |
|
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( |
) |
|
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( |
) |
|
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||
Loss on debt extinguishments |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Total other expenses |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
NET INCOME (LOSS) |
|
$ |
( |
) |
|
$ |
|
|
$ |
( |
) |
|
$ |
|
||
The accompanying notes are an integral part of these condensed consolidated financial statements.
6
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Condensed Consolidated Statements of Changes in Equity (Deficit)
(unaudited)
(in thousands, except share amounts)
|
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Series A Preferred Shares |
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Shares |
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Amount |
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Common Equity |
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Retained Earnings (Accumulated Deficit) |
|
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Total Equity (Deficit) |
|
|||||
Balance, December 31, 2025 |
|
|
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$ |
|
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$ |
|
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$ |
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$ |
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|||||
Amortization of Series A Preferred Shares discount |
|
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— |
|
|
|
|
|
|
— |
|
|
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( |
) |
|
|
— |
|
|
Distributions on Series A Preferred Shares |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
( |
) |
|
|
( |
) |
Net loss |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
( |
) |
|
|
( |
) |
Balance, March 31, 2026 |
|
|
|
|
$ |
|
|
$ |
|
|
$ |
( |
) |
|
$ |
( |
) |
|||
Amortization of Series A Preferred Shares discount |
|
|
— |
|
|
|
|
|
|
— |
|
|
|
( |
) |
|
|
— |
|
|
Distributions on Series A Preferred Shares |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
( |
) |
|
|
( |
) |
Net income |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
|
|
|
||
Balance, June 30, 2026 |
|
|
|
|
$ |
|
|
$ |
|
|
$ |
( |
) |
|
$ |
|
||||
Amortization of Series A Preferred Shares discount |
|
|
— |
|
|
|
|
|
|
— |
|
|
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( |
) |
|
|
— |
|
|
Distributions on Series A Preferred Shares |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
( |
) |
|
|
( |
) |
Net loss |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
( |
) |
|
|
( |
) |
Balance, September 30, 2026 |
|
|
|
|
$ |
|
|
$ |
|
|
$ |
( |
) |
|
$ |
|
||||
|
|
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|
|
|
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|
|||||
Balance, December 31, 2024 |
|
|
— |
|
|
$ |
— |
|
|
$ |
|
|
$ |
( |
) |
|
$ |
( |
) |
|
Net income |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
|
|
|
||
Balance, March 31, 2025 |
|
|
— |
|
|
$ |
— |
|
|
$ |
|
|
$ |
( |
) |
|
$ |
( |
) |
|
Net income |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
|
|
|
||
Balance, June 30, 2025 |
|
|
— |
|
|
$ |
— |
|
|
$ |
|
|
$ |
( |
) |
|
$ |
( |
) |
|
Net income |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
|
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||
Issuances of Series A Preferred Shares |
|
|
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|
|
|
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— |
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— |
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|
|||
Distributions on Series A Preferred Shares |
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|
— |
|
|
|
— |
|
|
|
— |
|
|
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( |
) |
|
|
( |
) |
Amortization of Series A Preferred Shares discount |
|
|
— |
|
|
|
|
|
|
— |
|
|
|
( |
) |
|
|
|
||
Balance, September 30, 2025 |
|
|
|
|
$ |
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|
$ |
|
|
$ |
( |
) |
|
$ |
|
||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
7
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Condensed Consolidated Statements of Cash Flows
(unaudited)
(in thousands)
|
|
Nine Months Ended |
|
|||||
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2026 |
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2025 |
|
||
CASH FLOWS FROM OPERATING ACTIVITIES |
|
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|
||
Net income (loss) |
|
$ |
( |
) |
|
$ |
|
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |
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Depreciation, depletion, and amortization |
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Equity-based compensation expense |
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Amortization of right-of-use assets |
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Amortization of debt discount and debt issuance costs |
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Noncash stated interest expense |
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Impairment expense |
|
|
|
|
|
|
||
Write-offs of earnest payments |
|
|
|
|
|
|
||
Unrealized (gain) loss on derivatives |
|
|
|
|
|
( |
) |
|
Loss on debt extinguishments |
|
|
|
|
|
|
||
Gain on sale of assets |
|
|
( |
) |
|
|
|
|
Changes in operating assets and liabilities: |
|
|
|
|
|
|
||
Accounts receivable |
|
|
( |
) |
|
|
( |
) |
Accounts receivable—related party |
|
|
( |
) |
|
|
|
|
Accounts payable |
|
|
|
|
|
|
||
Accrued expenses |
|
|
|
|
|
|
||
Derivative assets and liabilities, net |
|
|
|
|
|
|
||
Other current liabilities |
|
|
|
|
|
|
||
Escrow account |
|
|
( |
) |
|
|
( |
) |
Accrued interest |
|
|
( |
) |
|
|
( |
) |
Other operating activities |
|
|
( |
) |
|
|
|
|
Net cash provided by operating activities |
|
|
|
|
|
|
||
CASH FLOWS FROM INVESTING ACTIVITIES |
|
|
|
|
|
|
||
Additions to oil and gas properties and leases |
|
|
( |
) |
|
|
( |
) |
Proceeds from sale of assets |
|
|
|
|
|
|
||
Additions to other property and equipment |
|
|
( |
) |
|
|
( |
) |
Earnest payments for acquisition of properties |
|
|
( |
) |
|
|
( |
) |
Other investing activities |
|
|
|
|
|
( |
) |
|
Net cash used in investing activities |
|
|
( |
) |
|
|
( |
) |
CASH FLOWS FROM FINANCING ACTIVITIES |
|
|
|
|
|
|
||
Proceeds from issuances of debt, net of discount |
|
|
|
|
|
|
||
Payments of debt issuance costs |
|
|
( |
) |
|
|
( |
) |
Repayments of debt |
|
|
( |
) |
|
|
( |
) |
Proceeds from preferred equity offering, net of issuance costs |
|
|
|
|
|
|
||
Distributions on Series A Preferred Shares |
|
|
( |
) |
|
|
|
|
Payments of deferred closings |
|
|
( |
) |
|
|
( |
) |
Other financing activities |
|
|
|
|
|
|
||
Net cash provided by financing activities |
|
|
|
|
|
|
||
Net change in cash and cash equivalents |
|
|
|
|
|
( |
) |
|
Cash and cash equivalents at beginning of year |
|
|
|
|
|
|
||
Cash and cash equivalents at end of period |
|
$ |
|
|
$ |
|
||
The accompanying notes are an integral part of these condensed consolidated financial statements.
8
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements
(unaudited)
Note 1. Business
Phoenix Energy One, LLC (“Phoenix Energy”) is a Delaware limited liability company focused on oil and gas operations and acquisitions primarily in the Williston Basin, North Dakota/Montana, the Uinta Basin, Utah, the Permian Basin, Texas, the Denver-Julesburg Basin, Colorado/Wyoming and the Powder River Basin, Wyoming. The Company was formed in April 2019 as Phoenix Capital Group Holdings, LLC and changed its name to Phoenix Energy One, LLC in January 2025. As used in these condensed consolidated financial statements, unless the context otherwise requires, references to the “Company,” “we,” “us,” and “our” refer to Phoenix Energy and its consolidated subsidiaries.
The Company’s strategy involves the acquisition of royalty assets, non-operated working interests, and operated leaseholds for the purpose of exploration, development, production, and sale of crude oil, natural gas, natural gas liquids, and other byproducts conducted through its wholly-owned subsidiaries, Phoenix Operating LLC (“PhoenixOp”), Firebird Services, LLC (“Firebird Services”), and Firebird Marketing, LLC (“Firebird Marketing”). PhoenixOp is a Delaware limited liability company formed in January 2022 to drill, complete and operate wells in the United States. Firebird Services is a Delaware limited liability company formed in October 2023 to perform saltwater disposal services on wells operated by PhoenixOp. Firebird Marketing is a Delaware limited liability company formed in March 2025 to take title to oil at or near the wellhead and market production to third-party purchasers. It manages commercial and logistical activities related to the sale of hydrocarbons, including transportation coordination, blending and quality optimization, scheduling, and counterparty negotiations, and assumes market, operational and credit risks related thereto. In return, Firebird Marketing may earn marketing margins based on market conditions and its ability to optimize sales execution.
Interim financial presentation
The accompanying condensed consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) for interim financial information. Accordingly, they do not include all of the information and notes required by U.S. GAAP for annual financial statements. In the opinion of management, all adjustments, consisting only of normal recurring adjustments considered necessary for fair presentation, have been included. Interim results are not necessarily indicative of results for a full year. The accompanying unaudited condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto as of and for the year ended December 31, 2025.
Note 2. Significant Accounting Policies
Basis of preparation and principles of consolidation
The condensed consolidated financial statements include the accounts of Phoenix Energy and its wholly-owned subsidiaries. All intercompany accounts and transactions with and between Phoenix Energy and its wholly-owned subsidiaries have been eliminated in consolidation. Certain prior period amounts have been reclassified to conform to current period presentation. These reclassifications had no effect on the Company’s previously reported results of operations or retained earnings.
Liquidity risk and management’s plans
Liquidity risk is the risk that the Company’s cash flows from operations will not be sufficient for the Company to continue operating and discharge its liabilities in the normal course of operations. The Company is exposed to liquidity risk as its continued operation is dependent upon its ability to continue to obtain financing, either in the form of debt or equity, or by continuing to achieve profitable operations in order to satisfy its liabilities as they come due.
As of September 30, 2026, the Company had negative working capital of approximately $
The Company may conduct asset sales and/or issue debt or equity securities if liquidity risk increases in any given period. The Company believes it has sufficient funds to meet foreseeable obligations by actively monitoring its credit facilities through use of the loans, asset sales, cost reductions and coordinating payment and revenue cycles.
The Company is required to evaluate whether or not its current financial condition, including its sources of liquidity at the date that the condensed consolidated financial statements are issued, will enable the Company to meet its obligations as they come due within one year of the date of the issuance of these condensed consolidated financial statements and to make a
9
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements
(unaudited)
determination as to whether or not it is probable, under the application of this accounting guidance, that the Company will be able to continue as a going concern. In applying applicable accounting guidance, we considered the Company’s current financial condition and liquidity sources, including current funds available, forecasted future cash flows, the Company’s obligations due over the next twelve months as well as the Company’s recurring business operating expenses, and believe that the Company has sufficient financial resources to operate beyond the next twelve months following the date these condensed consolidated financial statements are issued.
Use of estimates
The preparation of the condensed consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, and the disclosure of contingent assets and liabilities at the date of the condensed consolidated financial statements and the reported amounts of revenues and expenses during the applicable reporting period of such statements. Accordingly, actual results could differ materially from these estimates.
The accompanying condensed consolidated financial statements are based on a number of significant estimates including quantities of oil, natural gas and NGL reserves that are the basis for the calculations of depreciation, depletion, amortization, and determinations of impairment of oil and natural gas properties. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas and there are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment along with estimated selling prices. As a result, reserve estimates may materially differ from the quantities of oil and natural gas that are ultimately recovered.
Inventory
Crude oil in storage tanks that has not yet been sold is classified as inventory and recorded within other current assets on the Company’s condensed consolidated balance sheets. Inventory is stated at the lower of cost and net realizable value, with cost determined using a weighted average cost method, and includes costs incurred to bring the inventory to its present location and condition.
Deferred contract costs
The Company capitalizes certain costs incurred to fulfill customer contracts when such costs relate directly to a contract, generate or enhance resources that will be used in satisfying future performance obligations, and are expected to be recovered. Deferred contract costs consist of aid-in-construction (“AIC”) payments made pursuant to a long-term natural gas gathering agreement and are recorded within other current and other noncurrent assets on the condensed consolidated balance sheets. As of September 30, 2026, the Company had $
Deferred contract costs are amortized on a straight-line basis over the estimated period of benefit beginning when the related gathering infrastructure is placed into service, and the associated economic benefits are realized and are recorded within cost of sales on the condensed consolidated statements of operations. No amortization expense related to deferred contract costs was recognized during the three and nine months ended September 30, 2026.
Oil and gas properties
The Company accounts for crude oil, natural gas, and NGL exploration and development activities using the successful efforts method of accounting. Under this method, costs to acquire, drill, and complete development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. Exploration costs, including geological and geophysical expenses and delay rentals for oil and gas leases, are expensed as incurred. Costs of drilling exploratory wells are initially capitalized but expensed if the well is determined to be unsuccessful. All capitalized well costs and leasehold costs of proved properties are depleted on a unit-of-production basis over the remaining life of proved developed reserves and total proved reserves, respectively, related to a geologic basin.
Recent accounting standards not yet adopted
In November 2024, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2024-03, Income Statement—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses (“ASU 2024-03”). ASU 2024-03 requires disclosure in the Company’s annual and interim consolidated financial statements of specified information about certain costs and expenses, including depletion, depreciation, and amortization recognized as part of crude oil and natural gas producing activities, cost of sales, selling, general, and administrative expenses, and employee compensation. This ASU is effective for annual reporting periods beginning after December 15, 2026, and
10
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements
(unaudited)
interim periods within fiscal years beginning after December 15, 2027. Early adoption is permitted. ASU 2024-03 can be applied prospectively or retrospectively at the Company’s election. The Company is currently evaluating the impact of the standard on its financial statements and disclosures and its plans for adoption, including the transition method and adoption date.
In December 2025, the FASB issued ASU 2025-11, Interim Reporting (Topic 270): Narrow-Scope Improvements (“ASU 2025-11”). ASU 2025-11 clarifies interim disclosure requirements and provides a comprehensive list of required interim disclosures. The update also incorporates a disclosure principle that requires entities to disclose events that occur after the end of the last annual reporting period. This update is effective for interim periods within annual periods beginning after December 15, 2027. Early adoption is permitted. The Company is currently evaluating the impact of the standard on its financial statements and disclosures.
Accounting pronouncements not listed above were assessed and determined to not have a material impact on the Company’s condensed consolidated financial statements.
Note 3. Property, Plant, and Equipment
The following table summarizes the Company’s property, plant, and equipment, net as of the dates presented:
(in thousands) |
|
September 30, 2026 |
|
|
December 31, 2025 |
|
||
Proved oil and natural gas properties(a) |
|
$ |
|
|
$ |
|
||
Unproved oil and natural gas properties |
|
|
|
|
|
|
||
Total oil and gas properties |
|
|
|
|
|
|
||
Other property and equipment |
|
|
|
|
|
|
||
Less: accumulated depreciation, depletion, and amortization |
|
|
( |
) |
|
|
( |
) |
Total property, plant, and equipment, net |
|
$ |
|
|
$ |
|
||
Depletion on oil and gas properties was $
Depreciation expense on the Company’s equipment and other property was $
Impairment expense on the Company’s oil and gas properties was $ million and $
11
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements
(unaudited)
Note 4. Revenue
The following tables present the Company’s revenues disaggregated by product type and by segment for the periods presented:
|
|
Three Months Ended September 30, 2026 |
|
|||||||||||||||||
(in thousands) |
|
Operating |
|
|
Mineral and Non-operating |
|
|
Securities |
|
|
Eliminations |
|
|
Total |
|
|||||
Product sales |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Crude oil |
|
$ |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
|
||
Natural gas |
|
|
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
||
NGL |
|
|
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
||
Total product sales |
|
|
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
||
Mineral and royalty revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Crude oil |
|
|
— |
|
|
|
|
|
|
— |
|
|
|
|
|
|
|
|||
Natural gas |
|
|
— |
|
|
|
|
|
|
— |
|
|
|
— |
|
|
|
|
||
NGL |
|
|
— |
|
|
|
|
|
|
— |
|
|
|
— |
|
|
|
|
||
Total mineral and royalty revenues |
|
|
— |
|
|
|
|
|
|
— |
|
|
|
|
|
|
|
|||
Purchased crude oil sales |
|
|
|
|
|
— |
|
|
|
— |
|
|
|
( |
) |
|
|
|
||
Water services |
|
|
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
||
Other revenue |
|
|
— |
|
|
|
— |
|
|
|
|
|
|
— |
|
|
|
|
||
Intersegment revenue |
|
|
— |
|
|
|
|
|
|
|
|
|
( |
) |
|
|
— |
|
||
Total revenues |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
( |
) |
|
$ |
|
||||
|
|
Three Months Ended September 30, 2025 |
|
|||||||||||||||||
(in thousands) |
|
Operating |
|
|
Mineral and Non-operating |
|
|
Securities |
|
|
Eliminations |
|
|
Total |
|
|||||
Product sales |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Crude oil |
|
$ |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
|
||
Natural gas |
|
|
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
||
NGL |
|
|
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
||
Total product sales |
|
|
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
||
Mineral and royalty revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Crude oil |
|
|
— |
|
|
|
|
|
|
— |
|
|
|
|
|
|
|
|||
Natural gas |
|
|
— |
|
|
|
|
|
|
— |
|
|
|
— |
|
|
|
|
||
NGL |
|
|
— |
|
|
|
|
|
|
— |
|
|
|
— |
|
|
|
|
||
Total mineral and royalty revenues |
|
|
— |
|
|
|
|
|
|
— |
|
|
|
|
|
|
|
|||
Purchased crude oil sales |
|
|
|
|
|
— |
|
|
|
— |
|
|
|
( |
) |
|
|
|
||
Water services |
|
|
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
||
Other revenue |
|
|
— |
|
|
|
— |
|
|
|
|
|
|
— |
|
|
|
|
||
Intersegment revenue |
|
|
— |
|
|
|
|
|
|
|
|
|
( |
) |
|
|
— |
|
||
Total revenues |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
( |
) |
|
$ |
|
||||
12
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements
(unaudited)
|
|
Nine Months Ended September 30, 2026 |
|
|||||||||||||||||
(in thousands) |
|
Operating |
|
|
Mineral and Non-operating |
|
|
Securities |
|
|
Eliminations |
|
|
Total |
|
|||||
Product sales |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Crude oil |
|
$ |
|
|
$ |
|
|
$ |
— |
|
|
$ |
|
|
$ |
|
||||
Natural gas |
|
|
|
|
|
|
|
|
— |
|
|
|
— |
|
|
|
|
|||
NGL |
|
|
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
||
Total product sales |
|
|
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
||
Mineral and royalty revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Crude oil |
|
|
|
|
|
|
|
|
— |
|
|
|
|
|
|
|
||||
Natural gas |
|
|
|
|
|
|
|
|
— |
|
|
|
— |
|
|
|
|
|||
NGL |
|
|
— |
|
|
|
|
|
|
— |
|
|
|
— |
|
|
|
|
||
Total mineral and royalty revenues |
|
|
— |
|
|
|
|
|
|
— |
|
|
|
|
|
|
|
|||
Purchased crude oil sales |
|
|
|
|
|
— |
|
|
|
— |
|
|
|
( |
) |
|
|
|
||
Water services |
|
|
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
||
Other revenue |
|
|
— |
|
|
|
— |
|
|
|
|
|
|
— |
|
|
|
|
||
Intersegment revenue |
|
|
— |
|
|
|
|
|
|
|
|
|
( |
) |
|
|
— |
|
||
Total revenues |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
( |
) |
|
$ |
|
||||
|
|
Nine Months Ended September 30, 2025 |
|
|||||||||||||||||
(in thousands) |
|
Operating |
|
|
Mineral and Non-operating |
|
|
Securities |
|
|
Eliminations |
|
|
Total |
|
|||||
Product sales |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Crude oil |
|
$ |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
|
||
Natural gas |
|
|
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
||
NGL |
|
|
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
||
Total product sales |
|
|
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
||
Mineral and royalty revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Crude oil |
|
|
— |
|
|
|
|
|
|
— |
|
|
|
|
|
|
|
|||
Natural gas |
|
|
— |
|
|
|
|
|
|
— |
|
|
|
— |
|
|
|
|
||
NGL |
|
|
— |
|
|
|
|
|
|
— |
|
|
|
— |
|
|
|
|
||
Total mineral and royalty revenues |
|
|
— |
|
|
|
|
|
|
— |
|
|
|
|
|
|
|
|||
Purchased crude oil sales |
|
|
|
|
|
— |
|
|
|
— |
|
|
|
( |
) |
|
|
|
||
Water services |
|
|
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
||
Other revenue |
|
|
— |
|
|
|
— |
|
|
|
|
|
|
— |
|
|
|
|
||
Intersegment revenue |
|
|
— |
|
|
|
|
|
|
|
|
|
( |
) |
|
|
— |
|
||
Total revenues |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
( |
) |
|
$ |
|
||||
Note 5. Other Current Assets
The following table summarizes the Company’s other current assets as of the dates presented:
(in thousands) |
|
September 30, 2026 |
|
|
December 31, 2025 |
|
||
Prepaid expenses |
|
$ |
|
|
$ |
|
||
Inventory |
|
|
|
|
|
|
||
Deposits |
|
|
|
|
|
|
||
Other |
|
|
|
|
|
|
||
Total |
|
$ |
|
|
$ |
|
||
Note 6. Derivatives
The Company periodically enters into commodity derivative contracts to manage its exposure to crude oil price risk. Additionally, the Company is required to hedge a portion of anticipated crude oil production for future periods pursuant to its debt covenants under the Fortress Credit Agreement, as further described in Note 7 – Debt. The Company does not enter into derivative contracts for speculative trading purposes.
The Company may enter into crude oil derivative contracts, including collars, fixed-price swaps, put options and call options, to hedge a portion of its anticipated future production and reduce exposure to commodity price volatility. Collars
13
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements
(unaudited)
establish both a floor and a ceiling price on contracted volumes, allowing the Company to receive payments if index prices fall below the floor, while requiring payments if index prices exceed the ceiling. Fixed-price swaps establish a fixed price for contracted volumes, resulting in payments to the Company when the index price is below the fixed price and payments by the Company when the index price exceeds the fixed price. Long call options are used to provide price protection in rising commodity price environments and provide the Company with the right to receive a cash settlement equal to the excess, if any, of the index price over the specified strike price, in exchange for the payment of an option premium. Long put options establish a floor price on contracted volumes and provide the Company with the right to receive a cash settlement equal to the excess, if any, of the strike price over the index price, in exchange for the payment of an option premium. Premiums on the Company's long call and put options are deferred and netted against monthly settlements. These instruments are settled net in cash and do not require the physical delivery of crude oil. As of September 30, 2026, the Company’s derivatives were comprised of crude oil commodity derivative contracts indexed to the U.S. New York Mercantile Exchange West Texas Intermediate (“NYMEX WTI”). The Company has not designated its derivative contracts for hedge accounting; therefore, changes in the fair value of these instruments, as well as cash settlements, are recognized in earnings in the period incurred. All derivative contracts are recorded at fair value on the condensed consolidated balance sheets as assets or liabilities and are presented on a net basis when a legally enforceable master netting arrangement exists with the counterparty.
As of September 30, 2026, the Company’s open crude oil derivative contracts consisted of the following:
|
|
Settlement Period |
|
|||||||||||||
(volumes in Bbl and prices in $/Bbl) |
|
2026 |
|
|
2027 |
|
|
2028 |
|
|
2029 |
|
||||
Two-Way Collars |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Notional Volumes |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Weighted Average Ceiling Price |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
||||
Weighted Average Floor Price |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
||||
Swaps |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Notional Volumes |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Weighted Average Contract Price |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
||||
Long Calls |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Notional Volumes |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Strike Price(a) |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
||||
Long Puts |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Notional Volumes |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Strike Price(b) |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
||||
The following table summarizes the gains and losses on derivative instruments included on the condensed consolidated statements of operations and the net cash payments related thereto for the periods presented.
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
||||||||||
(in thousands) |
|
2026 |
|
|
2025 |
|
|
2026 |
|
|
2025 |
|
||||
Gain (loss) on derivative instruments |
|
$ |
( |
) |
|
$ |
|
|
$ |
( |
) |
|
$ |
|
||
Net cash receipts (payments) on derivatives |
|
|
( |
) |
|
|
|
|
|
( |
) |
|
|
|
||
Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.
Certain assets and liabilities are reported at fair value on a recurring basis, including the Company’s derivative instruments. The Company obtains fair value estimates for its commodity derivative contracts from its counterparties and corroborates those estimates using observable market data. Significant inputs used to value the Company’s commodity derivative contracts are commodity futures price curves for the underlying commodities, contracted notional volumes, and remaining contractual terms. The resulting fair value measurements are classified within Level 2.
14
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements
(unaudited)
The following tables provide (i) fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis, (ii) the gross amounts of recognized derivative assets and liabilities, (iii) the amounts offset under master netting arrangements with counterparties, and (iv) the resulting net amounts presented in the Company’s condensed consolidated balance sheets as of September 30, 2026 and December 31, 2025. The net amounts are classified as current or noncurrent based on their anticipated settlement dates.
|
|
|
September 30, 2026 |
|
||||||||||||||||||||||
(in thousands) |
|
Balance Sheet |
|
Level 1 |
|
|
Level 2 |
|
|
Level 3 |
|
|
Total Gross Fair Value |
|
|
Gross Amounts Offset in Balance Sheet |
|
|
Net Fair Value Presented in Balance Sheet |
|
||||||
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Commodity derivatives |
|
Current derivative assets |
|
$ |
— |
|
|
$ |
|
|
$ |
— |
|
|
$ |
|
|
$ |
( |
) |
|
$ |
|
|||
Commodity derivatives |
|
Noncurrent derivative assets |
|
|
— |
|
|
|
|
|
|
— |
|
|
|
|
|
|
( |
) |
|
|
|
|||
Total assets |
|
|
|
$ |
— |
|
|
$ |
|
|
$ |
— |
|
|
$ |
|
|
$ |
( |
) |
|
$ |
|
|||
Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Commodity derivatives |
|
Current derivative liabilities |
|
$ |
— |
|
|
$ |
( |
) |
|
$ |
— |
|
|
$ |
( |
) |
|
$ |
|
|
$ |
( |
) |
|
Commodity derivatives |
|
Noncurrent derivative liabilities |
|
|
— |
|
|
|
( |
) |
|
|
— |
|
|
|
( |
) |
|
|
|
|
|
( |
) |
|
Total liabilities |
|
|
|
$ |
— |
|
|
$ |
( |
) |
|
$ |
— |
|
|
$ |
( |
) |
|
$ |
|
|
$ |
( |
) |
|
|
|
|
|
December 31, 2025 |
|
|||||||||||||||||||||
(in thousands) |
|
Balance Sheet |
|
Level 1 |
|
|
Level 2 |
|
|
Level 3 |
|
|
Total Gross Fair Value |
|
|
Gross Amounts Offset in Balance Sheet |
|
|
Net Fair Value Presented in Balance Sheet |
|
||||||
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Commodity derivatives |
|
Current derivative assets |
|
$ |
— |
|
|
$ |
|
|
$ |
— |
|
|
$ |
|
|
$ |
( |
) |
|
$ |
|
|||
Commodity derivatives |
|
Noncurrent derivative assets |
|
|
— |
|
|
|
|
|
|
— |
|
|
|
|
|
|
( |
) |
|
|
|
|||
Total assets |
|
|
|
$ |
— |
|
|
$ |
|
|
$ |
— |
|
|
$ |
|
|
$ |
( |
) |
|
$ |
|
|||
Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Commodity derivatives |
|
Current derivative liabilities |
|
$ |
— |
|
|
$ |
( |
) |
|
$ |
— |
|
|
$ |
( |
) |
|
$ |
|
|
$ |
|
||
Commodity derivatives |
|
Noncurrent derivative liabilities |
|
|
— |
|
|
|
( |
) |
|
|
— |
|
|
|
( |
) |
|
|
|
|
|
|
||
Total liabilities |
|
|
|
$ |
— |
|
|
$ |
( |
) |
|
$ |
— |
|
|
$ |
( |
) |
|
$ |
|
|
$ |
|
||
15
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements
(unaudited)
Note 7. Debt
The following table summarizes the Company’s long-term debt as of the dates presented:
|
|
Maturity Date |
|
|
|
|
|
|
|
|
||||||
(in thousands) |
|
Earliest |
|
|
Latest |
|
Interest Rate(a) |
|
September 30, |
|
|
December 31, |
|
|||
Fortress Term Loans |
|
|
— |
|
|
|
Term SOFR + |
|
$ |
|
|
$ |
|
|||
Unregistered Debt Offerings |
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Regulation D Bonds |
|
|
|
|
|
|
|
|
|
|
||||||
Adamantium Securities |
|
|
|
|
|
|
|
|
|
|
||||||
Regulation A Bonds |
|
|
|
|
|
|
|
|
|
|
||||||
Exchange Notes |
|
|
|
|
|
|
|
|
|
|
||||||
Total unregistered debt offerings |
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Registered Notes |
|
|
|
|
|
|
|
|
|
|
||||||
Phoenix Flex Notes |
|
|
|
|
|
|
|
|
|
|
||||||
Total outstanding debt |
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Less: Unamortized debt discount and issuance costs(b) |
|
|
|
|
|
|
|
|
|
( |
) |
|
|
( |
) |
|
Less: Current portion of long-term debt |
|
|
|
|
|
|
|
|
|
( |
) |
|
|
( |
) |
|
Total long-term debt, net of current portion |
|
|
|
|
|
|
|
|
$ |
|
|
$ |
|
|||
Fortress Credit Agreement
In August 2024, the Company entered into the Fortress Credit Agreement, which was subsequently amended to add additional term loan tranches and syndicated to include an additional institutional lender. In February 2026, the Fortress Credit Agreement was further amended to provide a $
As of September 30, 2026, the Company had $
The Fortress Term Loans are subject to
The all-in interest rate for the Fortress Term Loans was
The Fortress Credit Agreement contains various customary covenants, including financial covenants that require the Company to maintain ratios around its maximum total secured leverage, minimum asset coverage, current assets to current liabilities, and working capital as of the last day of each calendar month or fiscal quarter, as the case may be.
16
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements
(unaudited)
On October 21, 2026, subsequent to the balance sheet date, pursuant to the Limited Waiver and Amendment No. 11 to the Fortress Credit Agreement (“Amendment No. 11”), the Company obtained a waiver of noncompliance with its current ratio covenant for the calendar month ended September 30, 2026, which resulted primarily from the timing of accelerated well completion expenditures undertaken to capitalize on higher commodity prices. Amendment No. 11 also permits the Company to issue the Phoenix Access Notes, subject to the conditions and limitations described in the Fortress Credit Agreement.
Unregistered Debt Offerings
Regulation D Bonds
In March 2026, the Company approved an increase to the maximum offering amount of the August 2023 506(c) Bonds from $
Adamantium Securities
In March 2026, the Company amended the Adamantium Loan Agreement to increase the amount available to borrow under the agreement from $
Phoenix Flex Notes
In June 2026, the Company filed a registration statement on Form S-1 with the SEC, which was declared effective in July 2026, with respect to the continuous offering of up to an aggregate principal amount of $
In connection with the issuance of the Phoenix Access Notes, the Phoenix Flex Notes will become secured on a junior basis, equally and ratably with the Phoenix Access Notes, the Adamantium Loan Agreement, and any other indebtedness the Company may determine from time to time to be secured on a pari passu basis with the Phoenix Flex Notes, on substantially all of the collateral securing the Fortress Credit Agreement on a first-lien priority basis.
The Phoenix Flex Notes contain customary events of default and may be redeemed at the option of the Company at any time without premium or penalty. Subject to the subordination provisions applicable to the Phoenix Flex Notes, t
17
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements
(unaudited)
Interest Expense on Debt
The following table summarizes the total interest costs incurred on the Company’s debt:
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
||||||||||
(in thousands) |
|
2026 |
|
|
2025 |
|
|
2026 |
|
|
2025 |
|
||||
Stated interest |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
||||
Amortization of debt discount and debt issuance costs |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Total interest cost |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Capitalized interest |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Total interest expense, net |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
||||
Note 8. Other Current Liabilities
The following table summarizes the Company’s other current liabilities as of the dates presented:
(in thousands) |
|
September 30, 2026 |
|
|
December 31, 2025 |
|
||
Revenue payables |
|
$ |
|
|
$ |
|
||
Production taxes payable |
|
|
|
|
|
|
||
Advances from joint interest partners |
|
|
|
|
|
|
||
Accrued interest |
|
|
|
|
|
|
||
Unredeemed matured bonds |
|
|
|
|
|
|
||
Dividends payable |
|
|
|
|
|
|
||
Asset retirement obligations |
|
|
|
|
|
|
||
Other |
|
|
|
|
|
|
||
Total |
|
$ |
|
|
$ |
|
||
Note 9. Preferred Equity
In September 2025, the Company completed its offering of the Series A Preferred Shares, which shares were listed on the NYSE American under the ticker symbol PHXE.P and commenced trading on September 30, 2025. The Company sold an aggregate of
During the three and nine months ended September 30, 2026, the Company paid $
Note 10. Equity-Based Compensation
The Company’s parent, Phoenix Equity, has granted equity awards to employees and non-employee service providers of the Company under the 2024 Long-Term Incentive Plan (the “2024 Incentive Plan”).
A summary of the activity under the 2024 Incentive Plan for the nine months ended September 30, 2026 is presented below:
|
|
Number of Units |
|
|
Weighted Average Per Unit Grant Date Fair Value |
|
||
Nonvested at December 31, 2025 |
|
|
|
|
|
|
||
Granted - Phantom Units |
|
|
|
|
$ |
|
||
Vested |
|
|
( |
) |
|
$ |
|
|
Forfeited |
|
|
( |
) |
|
$ |
|
|
Nonvested at September 30, 2026 |
|
|
|
|
|
|
||
18
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements
(unaudited)
The Phantom Unit awards granted to employees are subject to both a performance condition and a service condition, each of which must be satisfied for the awards to vest. The performance condition requires the occurrence of an exit event (e.g., change in control) by the Company.
As of September 30, 2026 and December 31, 2025, there was $
The fair value of each unit granted under the 2024 Incentive Plan was valued on the date of grant under an independent third-party valuation, which included a combination of an income approach, based on the present value of estimated future cash flows, and a market approach based on market data of comparable businesses.
|
|
September 30, 2026 |
|
|
Dividend yield(a) |
|
|
% |
|
Risk-free interest rate(b) |
|
|
% |
|
Expected volatility(c) |
|
|
% |
|
Expected term (in years)(d) |
|
|
|
|
Discount for lack of marketability(e) |
|
|
% |
|
Note 11. Related Parties
Debt Offerings
Certain of the Company’s officers and their family members participate in the Company’s debt offerings. During the nine months ended September 30, 2026 and 2025, these officers and their family members purchased, in aggregate,
Lion of Judah
The Company paid interest to a financial institution on behalf of Lion of Judah Capital LLC (“Lion of Judah”) related to a certain financing agreement between Lion of Judah and the financial institution of less than $
Wellbore Participation
The Company has offered certain employees, including executive officers, the opportunity to acquire non-operated working interests in 38 Company-operated wells located in North Dakota and Montana. Participants acquired an aggregate
19
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements
(unaudited)
working interests. The participants’ aggregate share of forecasted development costs is approximately $
Note 12. Leases
The Company leases its office facilities primarily under noncancelable multi-year operating lease agreements.
The following table shows the line item classification of the Company’s right-of-use assets and lease liabilities on the Company’s condensed consolidated balance sheets:
(in thousands) |
|
Line item |
|
September 30, 2026 |
|
|
December 31, 2025 |
|
||
Right-of-use assets – operating |
|
Right-of-use assets, net |
|
$ |
|
|
$ |
|
||
Total right-of-use assets |
|
|
|
$ |
|
|
$ |
|
||
|
|
|
|
|
|
|
|
|
||
Current operating lease liabilities |
|
Current operating lease liabilities |
|
$ |
|
|
$ |
|
||
Noncurrent operating lease liabilities |
|
Operating lease liabilities |
|
|
|
|
|
|
||
Total lease liabilities |
|
|
|
$ |
|
|
$ |
|
||
Operating lease cost of $
Note 13. Commitments and Contingencies
For a summary of the Company’s lease obligations, see Note 12 – Leases.
Litigation
From time to time, the Company may become involved in other legal proceedings or be subject to claims arising in the ordinary course of business. Although the results of ordinary course litigation and claims cannot be predicted with certainty, the Company currently believes that the final outcome of these ordinary course matters will not have a material adverse effect on its business, financial condition, results of operations or cash flows. Regardless of the outcome, litigation can have an adverse impact because of defense and settlement costs, diversion of management resources and other factors.
Drilling Rig Contracts
The Company has entered into drilling rig contracts to procure drilling services for wells operated by PhoenixOp. The contracts are short-term and provide a daily operating rate as consideration for services performed by the third-party provider. The contracts provide for termination at the election of the Company but may include an early termination payment if the contract is terminated prior to the expiration of the fixed term.
Natural Gas Processing Contracts
The Company entered into contracts for mobile cryogenic gas processing units to process raw gas, produce and store NGL, and compress residue natural gas at wells operated by PhoenixOp. The contracts range from 6 months to 36 months and provide monthly facility and service fees as consideration for services performed by the third-party provider. As of September 30, 2026, the Company was subject to $
Generator Contracts
The Company entered into contracts with a third-party provider to supply generators used to provide power at wells operated by PhoenixOp. The contracts range from 12 months to 24 months and require monthly service payments for power generation and related equipment. As of September 30, 2026, the Company had approximately $
20
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements
(unaudited)
Saltwater Disposal Pump Contracts
The Company has entered into contracts for pumps which are used to inject produced water and flowback into its saltwater disposal facilities on wells for which PhoenixOp serves as the operator. The contracts provide for monthly payments and have terms of twelve months or less.
Delivery Commitments
Crude Oil Commitments
PhoenixOp is subject to arrangements pursuant to which it has committed to deliver barrels of crude oil to a purchaser through December 31, 2030. PhoenixOp will be subject to a shortfall fee for failure to meet this commitment. As a part of these arrangements, PhoenixOp has dedicated to the counterparties certain rights to all oil extracted from its wells in certain properties in Dunn County, North Dakota. PhoenixOp has assessed the productivity potential of its leasehold in the area, as well as the feasibility of executing an operational plan to extract oil on its leasehold within the commitment period and dedication area, and deemed it to be reasonable to enter into such an agreement. As of September 30, 2026, the Company delivered approximately
Natural Gas Gathering Commitments
In May 2026, the Company entered into a
Note 14. Supplemental Cash Flow Information
The following table summarizes supplemental information to the condensed consolidated statements of cash flows for the periods presented:
|
|
Nine Months Ended September 30, |
|
|||||
(in thousands) |
|
2026 |
|
|
2025 |
|
||
Supplemental disclosure of cash flow information: |
|
|
|
|
|
|
||
Cash interest paid, net of capitalized interest |
|
$ |
|
|
$ |
|
||
Cash paid for operating leases |
|
|
|
|
|
|
||
Supplemental disclosure of non-cash transactions: |
|
|
|
|
|
|
||
Capital expenditures in accounts payable and accrued expenses |
|
$ |
|
|
$ |
|
||
Conversion of accrued interest into principal |
|
|
|
|
|
|
||
Unredeemed matured bonds |
|
|
|
|
|
|
||
Unpaid property acquisition costs in deferred closings |
|
|
|
|
|
|
||
Distributions declared but unpaid on Series A Preferred Shares |
|
|
|
|
|
|
||
Amortization of Series A Preferred Shares discount |
|
|
|
|
|
|
||
Right-of-use asset obtained in exchange for lease liability |
|
|
|
|
|
|
||
Modification of right-of-use asset and lease liability |
|
|
|
|
|
|
||
21
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements
(unaudited)
Note 15. Segments
The following table summarizes segment operating profit and reconciliation to net income (loss) for the periods presented:
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
||||||||||
(in thousands) |
|
2026 |
|
|
2025 |
|
|
2026 |
|
|
2025 |
|
||||
Segment operating profit |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Operating |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
||||
Mineral and Non-operating |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Securities |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Eliminations |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Total segment operating profit |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Interest income |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Interest expense, net |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Gain (loss) on derivatives |
|
|
( |
) |
|
|
|
|
|
( |
) |
|
|
|
||
Loss on debt extinguishments |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Net income (loss) |
|
$ |
( |
) |
|
$ |
|
|
$ |
( |
) |
|
$ |
|
||
22
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements
(unaudited)
The following tables present financial information by segment for the three and nine months ended September 30, 2026 and 2025, and as of September 30, 2026 and December 31, 2025:
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
||||||||||
(in thousands) |
|
2026 |
|
|
2025 |
|
|
2026 |
|
|
2025 |
|
||||
Significant expenses |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Operating |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Cost of sales |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
||||
Depreciation, depletion, and amortization |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Purchased crude oil expenses |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Selling, general, and administrative(a) |
|
|
( |
) |
|
|
|
|
|
( |
) |
|
|
|
||
Payroll and payroll-related |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Other segment items(b) |
|
|
|
|
|
|
|
|
( |
) |
|
|
|
|||
Mineral and Non-operating |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Cost of sales |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
||||
Depreciation, depletion, and amortization |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Selling, general, and administrative |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Payroll and payroll-related |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Other segment items(c) |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Securities |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Selling, general, and administrative |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
||||
Payroll and payroll-related |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Advertising and marketing |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Interest expense |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Operating |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
||||
Mineral and Non-operating |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Securities |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Eliminations |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Total interest expense, net |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
||||
Capital expenditures |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Operating |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
||||
Mineral and Non-operating |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Eliminations |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
|
|
( |
) |
Total capital expenditures |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
||||
(in thousands) |
|
September 30, 2026 |
|
|
December 31, 2025 |
|
||
Assets |
|
|
|
|
|
|
||
Operating |
|
$ |
|
|
$ |
|
||
Mineral and Non-operating |
|
|
|
|
|
|
||
Securities |
|
|
|
|
|
|
||
Eliminations |
|
|
( |
) |
|
|
( |
) |
Total assets |
|
$ |
|
|
$ |
|
||
23
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements
(unaudited)
The following tables summarize the Company’s oil and natural gas properties by proved and unproved properties, location, and segment (before accumulated depletion):
|
|
September 30, 2026 |
|
|||||||||||||||||
(in thousands) |
|
Operating |
|
|
Mineral and |
|
|
Securities |
|
|
Eliminations |
|
|
Consolidated |
|
|||||
Oil and natural gas properties, proved |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Williston Basin |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|||||
Powder River Basin |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Denver-Julesburg |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Permian Basin |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Marcellus |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Uinta Basin |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Total proved properties |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|||||
Oil and natural gas properties, unproved |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Williston Basin |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|||||
Powder River Basin |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Denver-Julesburg |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Permian Basin |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Marcellus |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Uinta Basin |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Total unproved properties |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|||||
|
|
December 31, 2025 |
|
|||||||||||||||||
(in thousands) |
|
Operating |
|
|
Mineral and |
|
|
Securities |
|
|
Eliminations |
|
|
Consolidated |
|
|||||
Oil and natural gas properties, proved |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Williston Basin |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|||||
Powder River Basin |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Denver-Julesburg |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Permian Basin |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Marcellus |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Uinta Basin |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Total proved properties |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|||||
Oil and natural gas properties, unproved |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Williston Basin |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|||||
Powder River Basin |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Denver-Julesburg |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Permian Basin |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Uinta Basin |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Total unproved properties |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
|||||
Note 16. Subsequent Events
In connection with the preparation of these condensed consolidated financial statements, management has evaluated subsequent events through the date the condensed consolidated financial statements were issued. The Company has determined that there were no such material events that warrant disclosure or recognition on the condensed consolidated financial statements, except for the following:
In October 2026, the Company paid cash distributions totaling $
24
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements
(unaudited)
In October 2026, the Fortress Credit Agreement was further amended pursuant to Amendment No. 11 to permit the issuance of certain secured junior lien notes, including the Phoenix Access Notes, subject to the conditions and limitations described in the Fortress Credit Agreement. The amendment also revised certain covenants contained in the Fortress Credit Agreement and waived the Company’s noncompliance with its current ratio covenant for the calendar month ended September 30, 2026.
In October 2026, the Company filed a registration statement on Form S-1 with the SEC that relates to the issuance of up to $
The Company is continuing to raise debt capital under its exempt and registered debt offerings. Since the balance sheet date and through the date of filing of these condensed consolidated financial statements, the Company issued approximately $
25
Table of Contents
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with our condensed consolidated financial statements and the notes thereto presented in this Quarterly Report, as well as our audited financial statements and the related notes thereto and related management’s discussion and analysis in each case, included in our 2025 Annual Report. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs, and expected performance. These forward-looking statements are dependent upon events, risks, and uncertainties that may be outside of our control. Our actual results could differ materially from those disclosed in these forward-looking statements. Factors that could cause or contribute to such differences include those described in the section of our Quarterly Report entitled “Cautionary Statement Regarding Forward-Looking Statements,” in the section of our 2025 Annual Report entitled “Risk Factors,” and elsewhere in this Quarterly Report and in our 2025 Annual Report. Our historical results are not necessarily indicative of the results that may be expected for any period in the future.
Overview
We operate in the oil and gas industry and execute on a three-pronged strategy involving (i) direct drilling operations of operated working interests, (ii) the acquisition of royalty assets, and (iii) the acquisition of non-operated working interest assets. Our direct drilling operations are currently primarily focused on development efforts in the Williston Basin in North Dakota and Montana, and we plan to begin drilling in the Powder River Basin in Wyoming in 2027. Our royalty and working interest acquisitions center around a variety of assets, including mineral interests, leasehold interests, overriding royalty interests, and perpetual royalty interests. These efforts have historically targeted assets in the Williston, Permian, Powder River, Uinta, and Denver-Julesburg Basins. We are agnostic as to geography and prioritize operational and asset potential when executing on our strategy.
Our Segments
We operate under three segments: Operating; Mineral and Non-operating; and Securities. Our Operating segment comprises our operations related to our drilling, extraction, and production activities, which today are conducted through PhoenixOp and its wholly-owned subsidiary, Firebird Services. The sale and marketing of our operated production are conducted through Firebird Marketing. Our Mineral and Non-operating segment comprises our operations for the acquisition of mineral interests and non-operated working interests in oil and gas properties, through which we share in the proceeds of the natural resources extracted and sold by the operator. Our Securities segment comprises our operations related to our capital raising activities associated with our debt securities offerings. Our management evaluates our performance and allocates resources based in part on segment operating profit, which is calculated as total segment revenue less operating expenses attributable to the segment, which includes allocated corporate costs.
2026 Outlook
The following table presents our current estimates of certain financial and operating results for the full year of 2026. These forward-looking statements reflect our expectations as of the date of this Quarterly Report and are subject to substantial uncertainty. Our results are inherently unpredictable, may fluctuate significantly, and may be materially affected by many factors, such as fluctuations in commodity prices, changes in global economic and geopolitical conditions, which remain especially volatile, and changes in governmental regulations, among others. The following estimates are based on, among other things, our anticipated capital expenditures and drilling and operations programs, our ability to drill and complete wells consistent with our expectations, certain drilling, completion, and equipping cost assumptions, and certain well performance assumptions. In addition, achieving these estimates and maintaining the required drilling activity to achieve these estimates will depend on the availability of capital, the existing regulatory environment, commodity prices and differentials, rig and service availability, and actual drilling results, as well as other factors. Factors that could cause or contribute to changes of such estimates include those described in the sections entitled “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements” presented in our 2025 Annual Report. If any of these risks and uncertainties actually occur or the assumptions underlying our estimates are incorrect, our actual operating results, costs and activities may be materially and adversely different from our expectations or guidance. For example, we are currently monitoring our operations and industry developments in light of recent changes in the commodity price environment and industry volatility. While we believe we are well positioned to navigate a lower-price environment, which occasionally has materialized in the past years, a prolonged period of commodity prices below those assumed for purposes of our business plan and current estimates would have an adverse effect on our business, financial condition, results of operations, cash flows from operations, and 2026 outlook. If we adjust our business plan in response to such events, we may subsequently revise our 2026 outlook to reduce our expected ranges. For example, in such event, our expected ranges for revenue, net income (loss), EBITDA, Adjusted EBITDA, and production would likely decrease. Further, our total outstanding debt may increase to the extent we are required to raise additional capital, above our current expectations, in order to fully realize our current or adjusted business plan. In addition, investors should recognize that the reliability of any guidance diminishes to the extent that it involves estimates for figures further in the future,
26
Table of Contents
and so the further we are from the end of 2026 the more likely that our actual results will differ materially from our guidance. In light of the foregoing, investors are urged to put our guidance in context and not to place undue reliance upon it.
|
|
Year Ending December 31, 2026 |
|
|||||
(dollars in thousands) |
|
Lower Range |
|
|
Upper Range |
|
||
Revenue(1) |
|
$ |
1,610,000 |
|
|
$ |
1,780,000 |
|
Total operating expenses |
|
$ |
1,060,000 |
|
|
$ |
1,120,000 |
|
Net income (loss)(2) |
|
$ |
(40,000 |
) |
|
$ |
120,000 |
|
EBITDA(3) |
|
$ |
525,000 |
|
|
$ |
695,000 |
|
Adjusted EBITDA(3) |
|
$ |
725,000 |
|
|
$ |
850,000 |
|
Total outstanding debt(4) |
|
$ |
2,090,000 |
|
|
$ |
2,230,000 |
|
Production: |
|
|
|
|
|
|
||
Crude oil (Bbls) |
|
|
13,100,000 |
|
|
|
13,700,000 |
|
Natural gas (Mcf)(5) |
|
|
17,500,000 |
|
|
|
18,200,000 |
|
NGL (Bbls) |
|
|
1,550,000 |
|
|
|
1,640,000 |
|
Total (Boe) (6:1) |
|
|
17,566,667 |
|
|
|
18,373,333 |
|
Average daily production (Boe/d) (6:1) |
|
|
48,128 |
|
|
|
50,338 |
|
Third Quarter 2026 Financial and Operational Highlights
27
Table of Contents
28
Table of Contents
Results of Operations for the Three Months Ended September 30, 2026 Compared to the Three Months Ended September 30, 2025
The following table summarizes our consolidated results of operations for the periods indicated:
|
|
Three Months Ended September 30, |
|
|
Change |
|
||||||||||
(in thousands) |
|
2026 |
|
|
2025 |
|
|
$ |
|
|
% |
|
||||
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Product sales |
|
$ |
258,298 |
|
|
$ |
113,761 |
|
|
$ |
144,537 |
|
|
|
127.1 |
% |
Mineral and royalty revenues |
|
|
66,921 |
|
|
|
31,300 |
|
|
|
35,621 |
|
|
|
113.8 |
% |
Purchased crude oil sales |
|
|
126,905 |
|
|
|
40,436 |
|
|
|
86,469 |
|
|
|
213.8 |
% |
Water services |
|
|
8,103 |
|
|
|
3,308 |
|
|
|
4,795 |
|
|
|
145.0 |
% |
Other revenue |
|
|
158 |
|
|
|
216 |
|
|
|
(58 |
) |
|
|
(26.9 |
)% |
Total revenues |
|
|
460,385 |
|
|
|
189,021 |
|
|
|
271,364 |
|
|
|
143.6 |
% |
Operating expenses |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Cost of sales |
|
|
81,115 |
|
|
|
42,920 |
|
|
|
38,195 |
|
|
|
89.0 |
% |
Depreciation, depletion, and amortization |
|
|
88,743 |
|
|
|
45,550 |
|
|
|
43,193 |
|
|
|
94.8 |
% |
Purchased crude oil expenses |
|
|
123,206 |
|
|
|
39,623 |
|
|
|
83,583 |
|
|
|
210.9 |
% |
Selling, general, and administrative |
|
|
3,974 |
|
|
|
5,540 |
|
|
|
(1,566 |
) |
|
|
(28.3 |
)% |
Payroll and payroll-related |
|
|
13,514 |
|
|
|
6,437 |
|
|
|
7,077 |
|
|
|
109.9 |
% |
Advertising and marketing |
|
|
972 |
|
|
|
694 |
|
|
|
278 |
|
|
|
40.1 |
% |
Gain on sale of assets |
|
|
(210 |
) |
|
|
— |
|
|
|
(210 |
) |
|
NM |
|
|
Impairment expense |
|
|
646 |
|
|
|
1,987 |
|
|
|
(1,341 |
) |
|
|
(67.5 |
)% |
Total operating expenses |
|
|
311,960 |
|
|
|
142,751 |
|
|
|
169,209 |
|
|
|
118.5 |
% |
Income from operations |
|
|
148,425 |
|
|
|
46,270 |
|
|
|
102,155 |
|
|
|
220.8 |
% |
Other income (expenses) |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Interest income |
|
|
324 |
|
|
|
303 |
|
|
|
21 |
|
|
|
6.9 |
% |
Interest expense, net |
|
|
(61,575 |
) |
|
|
(38,816 |
) |
|
|
(22,759 |
) |
|
|
(58.6 |
)% |
Gain (loss) on derivatives |
|
|
(87,846 |
) |
|
|
2,065 |
|
|
|
(89,911 |
) |
|
|
(4,354.0 |
)% |
Loss on debt extinguishments |
|
|
(732 |
) |
|
|
(1,334 |
) |
|
|
602 |
|
|
|
45.1 |
% |
Total other expenses |
|
|
(149,829 |
) |
|
|
(37,782 |
) |
|
|
(112,047 |
) |
|
|
(296.6 |
)% |
Net income (loss) |
|
$ |
(1,404 |
) |
|
$ |
8,488 |
|
|
$ |
(9,892 |
) |
|
|
(116.5 |
)% |
NM – not meaningful.
The following tables summarize our segment operating profit for the periods indicated:
|
|
Three Months Ended September 30, 2026 |
|
|||||||||||||||||
(in thousands) |
|
Operating |
|
|
Mineral and |
|
|
Securities |
|
|
Eliminations |
|
|
Total |
|
|||||
Total revenues |
|
$ |
393,520 |
|
|
$ |
66,819 |
|
|
$ |
54,882 |
|
|
$ |
(54,836 |
) |
|
$ |
460,385 |
|
Total operating expenses |
|
|
(267,105 |
) |
|
|
(38,870 |
) |
|
|
(6,097 |
) |
|
|
112 |
|
|
|
(311,960 |
) |
Segment operating profit |
|
$ |
126,415 |
|
|
$ |
27,949 |
|
|
$ |
48,785 |
|
|
$ |
(54,724 |
) |
|
$ |
148,425 |
|
|
|
Three Months Ended September 30, 2025 |
|
|||||||||||||||||
(in thousands) |
|
Operating |
|
|
Mineral and |
|
|
Securities |
|
|
Eliminations |
|
|
Total |
|
|||||
Total revenues |
|
$ |
157,539 |
|
|
$ |
31,395 |
|
|
$ |
37,413 |
|
|
$ |
(37,326 |
) |
|
$ |
189,021 |
|
Total operating expenses |
|
|
(113,281 |
) |
|
|
(26,269 |
) |
|
|
(3,330 |
) |
|
|
129 |
|
|
|
(142,751 |
) |
Segment operating profit |
|
$ |
44,258 |
|
|
$ |
5,126 |
|
|
$ |
34,083 |
|
|
$ |
(37,197 |
) |
|
$ |
46,270 |
|
29
Table of Contents
The following table summarizes our net sales volumes and average realized prices for the periods indicated:
|
|
Three Months Ended September 30, |
|
|
Change |
|
||||||||||
|
|
2026 |
|
|
2025 |
|
|
$ |
|
|
% |
|
||||
Net Sales Volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Crude oil (Bbl) |
|
|
3,703,919 |
|
|
|
2,217,933 |
|
|
|
1,485,986 |
|
|
|
67.0 |
% |
Natural gas (Mcf) |
|
|
1,297,194 |
|
|
|
807,489 |
|
|
|
489,705 |
|
|
|
60.6 |
% |
NGL (Bbl) |
|
|
309,483 |
|
|
|
197,696 |
|
|
|
111,787 |
|
|
|
56.5 |
% |
Total (Boe)(6:1) |
|
|
4,229,601 |
|
|
|
2,550,211 |
|
|
|
1,679,390 |
|
|
|
65.9 |
% |
Average daily sales volumes (Boe/d) (6:1) |
|
|
45,974 |
|
|
|
27,720 |
|
|
|
18,254 |
|
|
|
65.9 |
% |
Average Realized Prices(a): |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Crude oil (Bbl) |
|
$ |
85.09 |
|
|
$ |
62.97 |
|
|
$ |
22.12 |
|
|
|
35.1 |
% |
Natural gas (Mcf) |
|
$ |
1.48 |
|
|
$ |
1.95 |
|
|
$ |
(0.47 |
) |
|
|
(24.1 |
)% |
NGL (Bbl) |
|
$ |
26.30 |
|
|
$ |
19.25 |
|
|
$ |
7.05 |
|
|
|
36.6 |
% |
Revenues
The following table shows the components of our revenue for the periods presented:
|
|
Three Months Ended September 30, |
|
|
Change |
|
||||||||||
(in thousands) |
|
2026 |
|
|
2025 |
|
|
$ |
|
|
% |
|
||||
Product sales |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Crude oil |
|
$ |
251,767 |
|
|
$ |
110,731 |
|
|
$ |
141,036 |
|
|
|
127.4 |
% |
Natural gas |
|
|
742 |
|
|
|
496 |
|
|
|
246 |
|
|
|
49.6 |
% |
NGL |
|
|
5,789 |
|
|
|
2,534 |
|
|
|
3,255 |
|
|
|
128.5 |
% |
Total product sales |
|
|
258,298 |
|
|
|
113,761 |
|
|
|
144,537 |
|
|
|
127.1 |
% |
Mineral and royalty revenues |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Crude oil |
|
|
63,399 |
|
|
|
28,949 |
|
|
|
34,450 |
|
|
|
119.0 |
% |
Natural gas |
|
|
1,173 |
|
|
|
1,079 |
|
|
|
94 |
|
|
|
8.7 |
% |
NGL |
|
|
2,349 |
|
|
|
1,272 |
|
|
|
1,077 |
|
|
|
84.7 |
% |
Total mineral and royalty revenues |
|
|
66,921 |
|
|
|
31,300 |
|
|
|
35,621 |
|
|
|
113.8 |
% |
Purchased crude oil sales |
|
|
126,905 |
|
|
|
40,436 |
|
|
|
86,469 |
|
|
|
213.8 |
% |
Water services |
|
|
8,103 |
|
|
|
3,308 |
|
|
|
4,795 |
|
|
|
145.0 |
% |
Other revenue |
|
|
158 |
|
|
|
216 |
|
|
|
(58 |
) |
|
|
(26.9 |
)% |
Total revenues |
|
$ |
460,385 |
|
|
$ |
189,021 |
|
|
$ |
271,364 |
|
|
|
143.6 |
% |
Revenue was $460.4 million for the three months ended September 30, 2026, as compared to $189.0 million for the same period in 2025, an increase of $271.4 million, or 143.6%. The increase was primarily attributable to a $144.5 million increase in product sales generated from our direct drilling, extraction, and related oil and gas operating activities, an $86.5 million increase in purchased crude oil sales derived from the sale of crude oil purchased from working interest owners and royalty interest holders in wells operated by PhoenixOp, a $35.6 million increase in mineral and royalty revenues generated from our mineral and non-operating activities, and a $4.8 million increase in revenue from water disposal services.
Operating Segment
Operating segment revenue was $393.5 million for the three months ended September 30, 2026, as compared to $157.5 million for the same period in 2025, an increase of $236.0 million, or 149.8%. The increase was primarily attributable to a $144.5 million increase in product sales generated from our direct drilling, extraction, and related oil and gas operating activities driven by additional wells placed into service, of which there were 150 producing wells in service as of September 30, 2026, as compared to 78 producing wells in service as of September 30, 2025, an $86.5 million increase in purchased crude oil sales attributable to Firebird Marketing’s crude oil marketing activities within the operating segment, and a $4.8 million increase in revenue from water disposal services driven by higher disposal volumes, with 14.2 million barrels of saltwater disposed by Firebird Services during the three months ended September 30, 2026, as compared to 6.8 million barrels during the same period in 2025. The increase in segment revenue was also driven by increased revenues from crude oil due to a 35.1% increase in average realized price for crude oil from $62.97/Bbl for the three months ended September 30, 2025 to $85.09/Bbl for the three months ended September 30, 2026. The increase in segment revenue was also driven by a 71.8% increase in crude oil production volumes during the three months ended September 30, 2026 as compared to the same period in 2025.
30
Table of Contents
Mineral and Non-operating Segment
Mineral and non-operating segment revenue was $66.8 million for the three months ended September 30, 2026, as compared to $31.4 million for the same period in 2025, an increase of $35.4 million, or 112.7%. The increase was primarily attributable to increased revenues from crude oil due to a 35.1% increase in the average realized price for crude oil from $62.97/Bbl for the three months ended September 30, 2025 to $85.09/Bbl for the three months ended September 30, 2026. The increase in segment revenue was also driven by a 51.0% increase in crude oil production volumes, as well as a 30.3% increase in natural gas production volumes from our acquisitions of mineral and non-operated working interests during the three months ended September 30, 2026 as compared to the same period in 2025.
Operating Expenses
Cost of Sales
The following table shows the components of our cost of sales for the periods presented:
|
|
Three Months Ended September 30, |
|
|
Change |
|
||||||||||
(in thousands) |
|
2026 |
|
|
2025 |
|
|
$ |
|
|
% |
|
||||
Cost of sales |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Production taxes |
|
$ |
30,401 |
|
|
$ |
11,648 |
|
|
$ |
18,753 |
|
|
|
161.0 |
% |
Lease operating expenses |
|
|
29,805 |
|
|
|
19,217 |
|
|
|
10,588 |
|
|
|
55.1 |
% |
Production costs |
|
|
20,909 |
|
|
|
12,055 |
|
|
|
8,854 |
|
|
|
73.4 |
% |
Total |
|
$ |
81,115 |
|
|
$ |
42,920 |
|
|
$ |
38,195 |
|
|
|
89.0 |
% |
Cost of sales was $81.1 million for the three months ended September 30, 2026, as compared to $42.9 million for the same period in 2025, an increase of $38.2 million, or 89.0%. The increase was primarily driven by increased drilling, extraction, and related oil and gas operating activities associated with wells operated by PhoenixOp, and an increase in cost of sales due to higher lease operating expense and severance taxes resulting from increased average realized price for crude oil and increased production volumes for crude oil and natural gas from our acquisitions of mineral and non-operated working interests during the three months ended September 30, 2026 as compared to the same period in 2025.
Operating Segment
Operating segment cost of sales was $67.8 million for the three months ended September 30, 2026, as compared to $36.1 million for the same period in 2025, an increase of $31.7 million, or 87.8%. The increase in segment cost of sales was driven by additional wells placed into service, of which there were 150 producing wells in service as of September 30, 2026, as compared to 78 producing wells in service as of September 30, 2025, resulting in increased lease operating expenses, production costs, and production and ad valorem taxes during the three months ended September 30, 2026 as compared to the same period in 2025.
Mineral and Non-operating Segment
Mineral and non-operating segment cost of sales was $13.4 million for the three months ended September 30, 2026, as compared to $6.9 million for the same period in 2025, an increase of $6.5 million, or 94.2%. The increase in segment cost of sales was primarily attributable to higher lease operating expense and severance taxes resulting from a 35.1% increase in the average realized price for crude oil from $62.97/Bbl for the three months ended September 30, 2025 to $85.09/Bbl for the three months ended September 30, 2026, and a 51.0% and 30.3% increase in production volumes for crude oil and natural gas, respectively, from our acquisitions of mineral and non-operated working interests during the three months ended September 30, 2026 as compared to the same period in 2025.
Depreciation, Depletion, and Amortization Expense
The following table shows the components of our depreciation, depletion, and amortization expense for the periods presented:
|
|
Three Months Ended September 30, |
|
|
Change |
|
||||||||||
(in thousands) |
|
2026 |
|
|
2025 |
|
|
$ |
|
|
% |
|
||||
Depreciation, depletion, and amortization |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Depletion |
|
$ |
88,243 |
|
|
$ |
45,463 |
|
|
$ |
42,780 |
|
|
|
94.1 |
% |
Depreciation |
|
|
349 |
|
|
|
12 |
|
|
|
337 |
|
|
|
2,808.3 |
% |
Amortization |
|
|
70 |
|
|
|
— |
|
|
|
70 |
|
|
NM |
|
|
Accretion on asset retirement obligations |
|
|
81 |
|
|
|
75 |
|
|
|
6 |
|
|
|
8.0 |
% |
Total |
|
$ |
88,743 |
|
|
$ |
45,550 |
|
|
$ |
43,193 |
|
|
|
94.8 |
% |
NM – not meaningful.
31
Table of Contents
Depreciation, depletion, and amortization expense was $88.7 million for the three months ended September 30, 2026, as compared to $45.6 million for the same period in 2025, an increase of $43.1 million, or 94.5%. The operating segment accounted for $35.1 million of the increase, primarily due to a $34.9 million increase in depletion expense. The mineral and non-operating segment accounted for $8.0 million of the increase, primarily due to a $7.9 million increase in depletion expense. In both segments, the increase in depletion expense was driven by higher production volumes and a higher depletion rate per Boe, which resulted from growth in the depletable cost base outpacing growth in proved reserves.
Operating Segment
Depreciation, depletion, and amortization expense for the operating segment was $70.4 million for the three months ended September 30, 2026, as compared to $35.3 million for the same period in 2025, an increase of $35.1 million, or 99.4%, primarily due to an increase in depletion expense driven by higher production volumes and a higher depletion rate, which resulted from growth in the depletable cost base outpacing growth in proved reserves.
Mineral and Non-operating Segment
Depreciation, depletion, and amortization expense for the mineral and non-operating segment was $18.3 million for the three months ended September 30, 2026, as compared to $10.3 million for the same period in 2025, an increase of $8.0 million, or 77.7%, primarily due to an increase in depletion expense driven by higher production volumes and a higher depletion rate. Depletion expense was $18.92 per Boe and $15.62 per Boe for the three months ended September 30, 2026 and 2025, respectively, an increase of $3.30 per Boe, primarily due to growth in the depletable cost base outpacing growth in proved reserves.
Purchased Crude Oil Expense
Purchased crude oil expense was $123.2 million for the three months ended September 30, 2026, as compared to $39.6 million for the same period in 2025, an increase of $83.6 million, or 211.1%. The increase in purchased crude oil expense was primarily driven by a 35.1% increase in average realized price for crude oil from $62.97/Bbl in the three months ended September 30, 2025 to $85.09/Bbl in the three months ended September 30, 2026, and a 71.8% increase in crude oil production volumes in our operated oil and gas properties.
Selling, General, and Administrative Expense
Selling, general, and administrative expense was $4.0 million for the three months ended September 30, 2026, as compared to $5.5 million for the same period in 2025, a decrease of $1.5 million, or 27.3%. The decrease was primarily due to a $2.9 million increase in the overhead attributable to field-level operations charged to operated wells, which reduced selling, general, and administrative expense, and a $1.7 million decrease in expense associated with land acquisition and title work, primarily resulting from the capitalization of costs directly associated with the acquisition of oil and gas properties. The decrease was partially offset by a $1.4 million increase in fees charged by purchasers for early revenue payments received within the operating segment, a $1.2 million increase in allocated corporate overhead, and a $0.7 million increase in legal professional service fees.
Operating Segment
Selling, general, and administrative expense for the operating segment was $(0.2) million for the three months ended September 30, 2026 as compared to less than $0.1 million for the same period in 2025, a change of $0.2 million, primarily due to a $2.9 million increase in the overhead attributable to field-level operations charged to operated wells, which reduced selling, general, and administrative expense, partially offset by increased fees charged by purchasers for early revenue payments received of $1.4 million, increased allocated corporate overhead of $0.7 million, a $0.2 million increase in fees associated with land acquisition and title work, increased legal professional service fees of $0.1 million, and a $0.1 million increase due to the reallocation of labor to other segments.
Mineral and Non-operating Segment
Selling, general, and administrative expense for the mineral and non-operating segment was $2.2 million for the three months ended September 30, 2026, as compared to $4.7 million for the same period in 2025, a decrease of $2.5 million, or 53.2%, primarily due to a $1.9 million decrease in fees associated with land acquisition and title work, a $0.5 million decrease due to the reallocation of labor to other segments, reflecting an alignment of employee time and responsibilities across segments, and decreased legal professional service fees of $0.1 million, partially offset by increased allocated corporate overhead of $0.2 million.
32
Table of Contents
Securities Segment
Selling, general, and administrative expense for the securities segment was $2.0 million for the three months ended September 30, 2026, as compared to $0.8 million for the same period in 2025, an increase of $1.2 million, or 150.0%, primarily due to increased legal professional service fees of $0.7 million and a $0.3 million increase in allocated corporate overhead.
Payroll and Payroll-Related Expense
Payroll and payroll-related expense was $13.5 million for the three months ended September 30, 2026, as compared to $6.4 million for the same period in 2025, an increase of $7.1 million, or 110.9%, primarily due to a $6.4 million increase in compensation paid to certain key employees. Employee headcount increased from 182 employees at September 30, 2025 to 184 employees at September 30, 2026.
Operating Segment
Payroll and payroll-related expense for the operating segment was $5.6 million for the three months ended September 30, 2026, as compared to $2.3 million for the same period in 2025, an increase of $3.3 million, or 143.5%, primarily due to a $2.1 million increase in compensation paid to certain key employees, the reallocation of personnel to our operating activities from other segments, and new hires supporting our oil and gas operations.
Mineral and Non-operating Segment
Payroll and payroll-related expense for the mineral and non-operating segment was $3.9 million for the three months ended September 30, 2026, as compared to $2.3 million for the same period in 2025, an increase of $1.6 million, or 69.6%, primarily due to a $2.1 million increase in compensation paid to certain key employees, partially offset by the capitalization of labor directly associated with the acquisition of oil and gas properties and the reallocation of personnel to other segments to better align employee time and responsibilities across segments.
Securities Segment
Payroll and payroll-related expense for the securities segment was $4.0 million for the three months ended September 30, 2026, as compared to $1.9 million for the same period in 2025, an increase of $2.1 million, or 110.5%, due to a $2.1 million increase in compensation paid to certain key employees.
Advertising and Marketing Expense
Advertising and marketing expense was $1.0 million for the three months ended September 30, 2026, as compared to $0.7 million for the same period in 2025, an increase of $0.3 million, or 42.9%, which was not material for the periods presented.
Gain on Sale of Assets
Gain on sale of assets was $0.2 million for the three months ended September 30, 2026, due to the conveyance of working interests in certain of our operated oil and gas properties, with no comparable activity during the same period in 2025.
Impairment Expense
Impairment expense was $0.7 million for the three months ended September 30, 2026, as compared to $2.0 million for the same period in 2025, a decrease of $1.3 million, or 65.0%, primarily due to a decrease in lease expirations and title defects within the mineral and non-operating segment.
Other Expenses
Interest Expense, Net
Interest expense, net, was $61.6 million for the three months ended September 30, 2026, as compared to $38.8 million for the same period in 2025, an increase of $22.8 million, or 58.8%. The increase was primarily due to (i) a $14.1 million increase in interest on our debt securities, as the principal outstanding increased from $1.0 billion at September 30, 2025 to $1.4 billion at September 30, 2026, with no significant change in the weighted-average interest rate, as our lower-rate Phoenix Flex Notes, first issued in July 2026, represented 1.1% of our total debt outstanding at September 30, 2026; (ii) a $5.5 million increase in interest under the Fortress Credit Agreement; (iii) a $1.5 million increase in amortization of debt issuance costs related to our debt securities; and (iv) a $1.8 million decrease in capitalized interest.
Gain (Loss) on Derivatives
Loss on derivatives was $87.8 million for the three months ended September 30, 2026, as compared to a gain on derivatives of $2.1 million for the same period in 2025, a change of $89.9 million, primarily attributable to a $62.8 million increase in unrealized losses as a result of unfavorable changes in the mark-to-market value of our outstanding commodity
33
Table of Contents
derivatives and a $27.1 million increase in realized losses, representing net cash settlements paid on matured contracts during the three months ended September 30, 2026 as compared to the same period in 2025.
Loss on Debt Extinguishments
Loss on debt extinguishments was $0.7 million for the three months ended September 30, 2026, as compared to $1.3 million for the same period in 2025, a decrease of $0.6 million, or 46.2%. The decrease was primarily due to decreased write-offs of debt issuance costs associated with the redemption of bonds issued pursuant to our debt offerings, of which $6.5 million of bonds were redeemed during the three months ended September 30, 2026, as compared to $7.1 million of bonds redeemed for the same period in 2025.
The following table summarizes the par value of bonds redeemed for the periods indicated:
|
|
Three Months Ended September 30, |
|
|
Change |
|
||||||||||
(in thousands) |
|
2026 |
|
|
2025 |
|
|
$ |
|
|
% |
|
||||
Reg D Bonds |
|
|
|
|
|
|
|
|
|
|
|
|
||||
August 2023 506(c) Bonds |
|
$ |
4,622 |
|
|
$ |
4,270 |
|
|
$ |
352 |
|
|
|
8.2 |
% |
Senior Reg D Bonds |
|
|
— |
|
|
|
100 |
|
|
|
(100 |
) |
|
|
(100.0 |
)% |
December 2022 506(c) Bonds |
|
|
344 |
|
|
|
429 |
|
|
|
(85 |
) |
|
|
(19.8 |
)% |
Total Reg D Bonds |
|
|
4,966 |
|
|
|
4,799 |
|
|
|
167 |
|
|
|
3.5 |
% |
Reg A Bonds |
|
|
45 |
|
|
|
721 |
|
|
|
(676 |
) |
|
|
(93.8 |
)% |
Adamantium Bonds |
|
|
895 |
|
|
|
1,563 |
|
|
|
(668 |
) |
|
|
(42.7 |
)% |
Registered Notes |
|
|
108 |
|
|
|
15 |
|
|
|
93 |
|
|
|
620.0 |
% |
Exchange Notes |
|
|
470 |
|
|
|
— |
|
|
|
470 |
|
|
NM |
|
|
Total |
|
$ |
6,484 |
|
|
$ |
7,098 |
|
|
$ |
(614 |
) |
|
|
(8.7 |
)% |
NM – not meaningful.
34
Table of Contents
Results of Operations for the Nine Months Ended September 30, 2026 Compared to the Nine Months Ended September 30, 2025
The following table summarizes our consolidated results of operations for the periods indicated:
|
|
Nine Months Ended September 30, |
|
|
Change |
|
||||||||||
(in thousands) |
|
2026 |
|
|
2025 |
|
|
$ |
|
|
% |
|
||||
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Product sales |
|
$ |
681,799 |
|
|
$ |
295,290 |
|
|
$ |
386,509 |
|
|
|
130.9 |
% |
Mineral and royalty revenues |
|
|
151,766 |
|
|
|
93,171 |
|
|
|
58,595 |
|
|
|
62.9 |
% |
Purchased crude oil sales |
|
|
311,958 |
|
|
|
71,236 |
|
|
|
240,722 |
|
|
|
337.9 |
% |
Water services |
|
|
18,443 |
|
|
|
8,508 |
|
|
|
9,935 |
|
|
|
116.8 |
% |
Other revenue |
|
|
950 |
|
|
|
397 |
|
|
|
553 |
|
|
|
139.3 |
% |
Total revenues |
|
|
1,164,916 |
|
|
|
468,602 |
|
|
|
696,314 |
|
|
|
148.6 |
% |
Operating expenses |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Cost of sales |
|
|
188,787 |
|
|
|
105,172 |
|
|
|
83,615 |
|
|
|
79.5 |
% |
Depreciation, depletion, and amortization |
|
|
223,245 |
|
|
|
113,392 |
|
|
|
109,853 |
|
|
|
96.9 |
% |
Purchased crude oil expenses |
|
|
303,802 |
|
|
|
69,975 |
|
|
|
233,827 |
|
|
|
334.2 |
% |
Selling, general, and administrative |
|
|
11,080 |
|
|
|
21,435 |
|
|
|
(10,355 |
) |
|
|
(48.3 |
)% |
Payroll and payroll-related |
|
|
31,906 |
|
|
|
22,459 |
|
|
|
9,447 |
|
|
|
42.1 |
% |
Advertising and marketing |
|
|
1,898 |
|
|
|
1,531 |
|
|
|
367 |
|
|
|
24.0 |
% |
Gain on sale of assets |
|
|
(1,652 |
) |
|
|
— |
|
|
|
(1,652 |
) |
|
NM |
|
|
Impairment expense |
|
|
2,056 |
|
|
|
2,509 |
|
|
|
(453 |
) |
|
|
(18.1 |
)% |
Total operating expenses |
|
|
761,122 |
|
|
|
336,473 |
|
|
|
424,649 |
|
|
|
126.2 |
% |
Income from operations |
|
|
403,794 |
|
|
|
132,129 |
|
|
|
271,665 |
|
|
|
205.6 |
% |
Other income (expenses) |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Interest income |
|
|
712 |
|
|
|
1,355 |
|
|
|
(643 |
) |
|
|
(47.5 |
)% |
Interest expense, net |
|
|
(172,414 |
) |
|
|
(111,690 |
) |
|
|
(60,724 |
) |
|
|
(54.4 |
)% |
Gain (loss) on derivatives |
|
|
(265,030 |
) |
|
|
12,907 |
|
|
|
(277,937 |
) |
|
|
(2,153.4 |
)% |
Loss on debt extinguishments |
|
|
(2,600 |
) |
|
|
(1,916 |
) |
|
|
(684 |
) |
|
|
(35.7 |
)% |
Total other expenses |
|
|
(439,332 |
) |
|
|
(99,344 |
) |
|
|
(339,988 |
) |
|
|
(342.2 |
)% |
Net income (loss) |
|
$ |
(35,538 |
) |
|
$ |
32,785 |
|
|
$ |
(68,323 |
) |
|
|
(208.4 |
)% |
NM – not meaningful.
The following tables summarize our segment operating profit for the periods indicated:
|
|
Nine Months Ended September 30, 2026 |
|
|||||||||||||||||
(in thousands) |
|
Operating |
|
|
Mineral and |
|
|
Securities |
|
|
Eliminations |
|
|
Total |
|
|||||
Total revenues |
|
$ |
1,012,731 |
|
|
$ |
151,811 |
|
|
$ |
150,400 |
|
|
$ |
(150,026 |
) |
|
$ |
1,164,916 |
|
Total operating expenses |
|
|
(654,821 |
) |
|
|
(91,430 |
) |
|
|
(15,447 |
) |
|
|
576 |
|
|
|
(761,122 |
) |
Segment operating profit |
|
$ |
357,910 |
|
|
$ |
60,381 |
|
|
$ |
134,953 |
|
|
$ |
(149,450 |
) |
|
$ |
403,794 |
|
|
|
Nine Months Ended September 30, 2025 |
|
|||||||||||||||||
(in thousands) |
|
Operating |
|
|
Mineral and |
|
|
Securities |
|
|
Eliminations |
|
|
Total |
|
|||||
Total revenues |
|
$ |
375,098 |
|
|
$ |
93,336 |
|
|
$ |
100,732 |
|
|
$ |
(100,564 |
) |
|
$ |
468,602 |
|
Total operating expenses |
|
|
(254,674 |
) |
|
|
(71,045 |
) |
|
|
(10,983 |
) |
|
|
229 |
|
|
|
(336,473 |
) |
Segment operating profit |
|
$ |
120,424 |
|
|
$ |
22,291 |
|
|
$ |
89,749 |
|
|
$ |
(100,335 |
) |
|
$ |
132,129 |
|
35
Table of Contents
The following table summarizes our net sales volumes and average realized prices for the periods indicated:
|
|
Nine Months Ended September 30, |
|
|
Change |
|
||||||||||
|
|
2026 |
|
|
2025 |
|
|
$ |
|
|
% |
|
||||
Net Sales Volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Crude oil (Bbl) |
|
|
9,687,251 |
|
|
|
5,731,412 |
|
|
|
3,955,839 |
|
|
|
69.0 |
% |
Natural gas (Mcf) |
|
|
4,263,360 |
|
|
|
2,146,843 |
|
|
|
2,116,517 |
|
|
|
98.6 |
% |
NGL (Bbl) |
|
|
850,878 |
|
|
|
388,083 |
|
|
|
462,795 |
|
|
|
119.3 |
% |
Total (Boe)(6:1) |
|
|
11,248,689 |
|
|
|
6,477,302 |
|
|
|
4,771,387 |
|
|
|
73.7 |
% |
Average daily sales volumes (Boe/d) (6:1) |
|
|
41,204 |
|
|
|
23,726 |
|
|
|
17,478 |
|
|
|
73.7 |
% |
Average Realized Prices(a): |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Crude oil (Bbl) |
|
$ |
82.78 |
|
|
$ |
65.36 |
|
|
$ |
17.42 |
|
|
|
26.7 |
% |
Natural gas (Mcf) |
|
$ |
2.39 |
|
|
$ |
2.57 |
|
|
$ |
(0.18 |
) |
|
|
(7.0 |
)% |
NGL (Bbl) |
|
$ |
25.22 |
|
|
$ |
21.51 |
|
|
$ |
3.71 |
|
|
|
17.2 |
% |
Revenues
The following table shows the components of our revenue for the periods presented:
|
|
Nine Months Ended September 30, |
|
|
Change |
|
||||||||||
(in thousands) |
|
2026 |
|
|
2025 |
|
|
$ |
|
|
% |
|
||||
Product sales |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Crude oil |
|
$ |
661,349 |
|
|
$ |
290,371 |
|
|
$ |
370,978 |
|
|
|
127.8 |
% |
Natural gas |
|
|
5,179 |
|
|
|
1,133 |
|
|
|
4,046 |
|
|
|
357.1 |
% |
NGL |
|
|
15,271 |
|
|
|
3,786 |
|
|
|
11,485 |
|
|
|
303.4 |
% |
Total product sales |
|
|
681,799 |
|
|
|
295,290 |
|
|
|
386,509 |
|
|
|
130.9 |
% |
Mineral and royalty revenues |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Crude oil |
|
|
140,582 |
|
|
|
84,235 |
|
|
|
56,347 |
|
|
|
66.9 |
% |
Natural gas |
|
|
4,996 |
|
|
|
4,374 |
|
|
|
622 |
|
|
|
14.2 |
% |
NGL |
|
|
6,188 |
|
|
|
4,562 |
|
|
|
1,626 |
|
|
|
35.6 |
% |
Total mineral and royalty revenues |
|
|
151,766 |
|
|
|
93,171 |
|
|
|
58,595 |
|
|
|
62.9 |
% |
Purchased crude oil sales |
|
|
311,958 |
|
|
|
71,236 |
|
|
|
240,722 |
|
|
|
337.9 |
% |
Water services |
|
|
18,443 |
|
|
|
8,508 |
|
|
|
9,935 |
|
|
|
116.8 |
% |
Other revenue |
|
|
950 |
|
|
|
397 |
|
|
|
553 |
|
|
|
139.3 |
% |
Total revenues |
|
$ |
1,164,916 |
|
|
$ |
468,602 |
|
|
$ |
696,314 |
|
|
|
148.6 |
% |
Revenue was $1.2 billion for the nine months ended September 30, 2026, as compared to $468.6 million for the same period in 2025, an increase of $696.3 million, or 148.6%. The increase was primarily attributable to a $386.5 million increase in product sales generated from our direct drilling, extraction, and related oil and gas operating activities, a $240.7 million increase in purchased crude oil sales derived from the sale of crude oil purchased from working interest owners and royalty interest holders in wells operated by PhoenixOp, a $58.6 million increase in mineral and royalty revenues generated from our mineral and non-operating activities, and a $9.9 million increase in revenue from water disposal services.
Operating Segment
Operating segment revenue was $1.0 billion for the nine months ended September 30, 2026, as compared to $375.1 million for the same period in 2025, an increase of $637.6 million, or 170.0%. The increase was primarily attributable to a $386.5 million increase in product sales generated from our direct drilling, extraction, and related oil and gas operating activities driven by additional wells placed into service, of which there were 150 producing wells in service as of September 30, 2026, as compared to 78 producing wells in service as of September 30, 2025, and a $240.7 million increase in purchased crude oil sales attributable to Firebird Marketing’s crude oil marketing activities within the operating segment, which were in place for the full nine months ended September 30, 2026, compared to a partial period in 2025, as these activities commenced in April 2025. The increase was also driven by a $9.9 million increase in revenue from water disposal services driven by higher disposal volumes, with 38.7 million barrels of saltwater disposed by Firebird Services during the nine months ended September 30, 2026, as compared to 15.8 million barrels during the same period in 2025, and increased revenues from crude oil due to a 26.7% increase in average realized price for crude oil from $65.36/Bbl for the nine months ended September 30, 2025 to $82.78/Bbl for the nine months ended September 30, 2026. The increase in segment revenue was also driven by an
36
Table of Contents
80.8% increase in crude oil production volumes during the nine months ended September 30, 2026 as compared to the same period in 2025.
Mineral and Non-operating Segment
Mineral and non-operating segment revenue was $151.8 million for the nine months ended September 30, 2026, as compared to $93.3 million for the same period in 2025, an increase of $58.5 million, or 62.7%. The increase was primarily attributable to increased revenues from crude oil due to a 26.7% increase in the average realized price for crude oil from $65.36/Bbl for the nine months ended September 30, 2025 to $82.78/Bbl for the nine months ended September 30, 2026. The increase in segment revenue was also driven by a 30.9% increase in crude oil production volumes, as well as a 31.4% increase in natural gas production volumes from our acquisitions of mineral and non-operated working interests during the nine months ended September 30, 2026 as compared to the same period in 2025.
Operating Expenses
Cost of Sales
The following table shows the components of our cost of sales for the periods presented:
|
|
Nine Months Ended September 30, |
|
|
Change |
|
||||||||||
(in thousands) |
|
2026 |
|
|
2025 |
|
|
$ |
|
|
% |
|
||||
Cost of sales |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Production taxes |
|
$ |
76,965 |
|
|
$ |
32,383 |
|
|
$ |
44,582 |
|
|
|
137.7 |
% |
Lease operating expenses |
|
|
61,565 |
|
|
|
40,810 |
|
|
|
20,755 |
|
|
|
50.9 |
% |
Production costs |
|
|
50,257 |
|
|
|
31,979 |
|
|
|
18,278 |
|
|
|
57.2 |
% |
Total |
|
$ |
188,787 |
|
|
$ |
105,172 |
|
|
$ |
83,615 |
|
|
|
79.5 |
% |
Cost of sales was $188.8 million for the nine months ended September 30, 2026, as compared to $105.2 million for the same period in 2025, an increase of $83.6 million, or 79.5%. The increase was primarily driven by increased drilling, extraction, and related oil and gas operating activities associated with wells operated by PhoenixOp, and an increase in cost of sales due to higher lease operating expense and severance taxes resulting from increased average realized price for crude oil and increased production volumes for crude oil and natural gas from our acquisitions of mineral and non-operated working interests during the nine months ended September 30, 2026 as compared to the same period in 2025.
Operating Segment
Operating segment cost of sales was $160.2 million for the nine months ended September 30, 2026, as compared to $87.2 million for the same period in 2025, an increase of $73.0 million, or 83.7%. The increase in segment cost of sales was driven by additional wells placed into service, of which there were 150 producing wells in service as of September 30, 2026, as compared to 78 producing wells in service as of September 30, 2025, resulting in increased lease operating expenses, production costs, and production and ad valorem taxes during the nine months ended September 30, 2026 as compared to the same period in 2025.
Mineral and Non-operating Segment
Mineral and non-operating segment cost of sales was $29.2 million for the nine months ended September 30, 2026, as compared to $18.2 million for the same period in 2025, an increase of $11.0 million, or 60.4%. The increase in segment cost of sales was primarily attributable to higher lease operating expense and severance taxes resulting from a 26.7% increase in the average realized price for crude oil from $65.36/Bbl for the nine months ended September 30, 2025 to $82.78/Bbl for the nine months ended September 30, 2026, and a 30.9% and 31.4% increase in production volumes for crude oil and natural gas, respectively, from our acquisitions of mineral and non-operated working interests during the nine months ended September 30, 2026 as compared to the same period in 2025.
37
Table of Contents
Depreciation, Depletion, and Amortization Expense
The following table shows the components of our depreciation, depletion, and amortization expense for the periods presented:
|
|
Nine Months Ended September 30, |
|
|
Change |
|
||||||||||
(in thousands) |
|
2026 |
|
|
2025 |
|
|
$ |
|
|
% |
|
||||
Depreciation, depletion, and amortization |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Depletion |
|
$ |
222,067 |
|
|
$ |
113,278 |
|
|
$ |
108,789 |
|
|
|
96.0 |
% |
Depreciation |
|
|
717 |
|
|
|
26 |
|
|
|
691 |
|
|
|
2,657.7 |
% |
Amortization |
|
|
210 |
|
|
|
— |
|
|
|
210 |
|
|
NM |
|
|
Accretion on asset retirement obligations |
|
|
251 |
|
|
|
88 |
|
|
|
163 |
|
|
|
185.2 |
% |
Total |
|
$ |
223,245 |
|
|
$ |
113,392 |
|
|
$ |
109,853 |
|
|
|
96.9 |
% |
NM – not meaningful
Depreciation, depletion, and amortization expense was $223.2 million for the nine months ended September 30, 2026, as compared to $113.4 million for the same period in 2025, an increase of $109.8 million, or 96.8%. The operating segment accounted for $92.0 million of the increase, primarily due to a $91.3 million increase in depletion expense. The mineral and non-operating segment accounted for $17.9 million of the increase, primarily due to a $17.4 million increase in depletion expense. In both segments, the increase in depletion expense was driven by higher production volumes and a higher depletion rate per Boe, which resulted from growth in the depletable cost base outpacing growth in proved reserves.
Operating Segment
Depreciation, depletion, and amortization expense for the operating segment was $179.8 million for the nine months ended September 30, 2026, as compared to $87.8 million for the same period in 2025, an increase of $92.0 million, or 104.8%, primarily due to an increase in depletion expense driven by higher production volumes and a higher depletion rate, which resulted from growth in the depletable cost base outpacing growth in proved reserves.
Mineral and Non-operating Segment
Depreciation, depletion, and amortization expense for the mineral and non-operating segment was $43.5 million for the nine months ended September 30, 2026, as compared to $25.6 million for the same period in 2025, an increase of $17.9 million, or 69.9%, primarily due to an increase in depletion expense driven by higher production volumes and a higher depletion rate. Depletion expense was $17.99 per Boe and $14.01 per Boe for the nine months ended September 30, 2026 and 2025, respectively, an increase of $3.98 per Boe, primarily due to growth in the depletable cost base outpacing growth in proved reserves.
Purchased Crude Oil Expense
Purchased crude oil expense was $303.8 million for the nine months ended September 30, 2026, as compared to $70.0 million for the same period in 2025, an increase of $233.8 million, or 334.0%. The increase in purchased crude oil expense was primarily attributable to Firebird Marketing’s crude oil marketing activities within the operating segment, which were in place for the full nine months ended September 30, 2026, compared to a partial period in 2025, as these activities commenced in April 2025. The increase was also driven by a 26.7% increase in the average realized price for crude oil from $65.36/Bbl for the nine months ended September 30, 2025 to $82.78/Bbl for the nine months ended September 30, 2026, and an 80.8% increase in crude oil production volumes in our operated oil and gas properties.
Selling, General, and Administrative Expense
Selling, general, and administrative expense was $11.1 million for the nine months ended September 30, 2026, as compared to $21.4 million for the same period in 2025, a decrease of $10.3 million, or 48.1%. The decrease was primarily due to a $12.6 million increase in the overhead attributable to field-level operations charged to operated wells, which reduced selling, general, and administrative expense, partially offset by a $2.6 million increase in allocated corporate overhead.
Operating Segment
Selling, general, and administrative expense for the operating segment was $(1.4) million for the nine months ended September 30, 2026, as compared to $3.1 million for the same period in 2025, a change of $4.5 million, primarily due to a $12.6 million increase in the overhead attributable to field-level operations charged to operated wells, which reduced selling, general, and administrative expense, partially offset by increased allocated corporate overhead of $2.6 million, increased fees charged by purchasers for early revenue payments received of $3.1 million, a $1.2 million increase in expenses associated with land acquisition and title work allocated to the operating segment, a $0.6 million increase due to the reallocation of labor to
38
Table of Contents
other segments, reflecting an alignment of employee time and responsibilities across segments, and increased professional service fees within the operating segment of $0.2 million.
Mineral and Non-operating Segment
Selling, general, and administrative expense for the mineral and non-operating segment was $6.8 million for the nine months ended September 30, 2026, as compared to $14.5 million for the same period in 2025, a decrease of $7.7 million, or 53.1%. The decrease was primarily due to a $4.6 million decrease in fees associated with land acquisition and title work, primarily resulting from the capitalization of costs directly associated with the acquisition of oil and gas properties, a $1.2 million decrease due to the reallocation of labor to other segments, reflecting an alignment of employee time and responsibilities across segments, decreased legal professional service fees of $1.0 million, and decreased allocated corporate overhead of $0.7 million.
Securities Segment
Selling, general, and administrative expense for the securities segment was $5.7 million for the nine months ended September 30, 2026, as compared to $3.8 million for the same period in 2025, an increase of $1.9 million, or 50.0%, primarily due to increased legal professional service fees of $1.1 million and increased allocated corporate overhead of $0.7 million.
Payroll and Payroll-Related Expense
Payroll and payroll-related expense was $31.9 million for the nine months ended September 30, 2026, as compared to $22.5 million for the same period in 2025, an increase of $9.4 million, or 41.8%, primarily due to a $7.5 million increase in compensation paid to certain key employees and increased employee headcount and compensation to other employees. Employee headcount increased from 182 employees at September 30, 2025 to 184 employees at September 30, 2026.
Operating Segment
Payroll and payroll-related expense for the operating segment was $13.3 million for the nine months ended September 30, 2026, as compared to $6.7 million for the same period in 2025, an increase of $6.6 million, or 98.5%, primarily due to a $2.5 million increase in compensation paid to certain key employees, the reallocation of personnel to our operating activities from other segments, and new hires supporting our oil and gas operations.
Mineral and Non-operating Segment
Payroll and payroll-related expense for the mineral and non-operating segment was $9.2 million for the nine months ended September 30, 2026, as compared to $10.2 million for the same period in 2025, a decrease of $1.0 million, or 9.8%, primarily due to the capitalization of labor directly associated with the acquisition of oil and gas properties and the reallocation of personnel to other segments to better align employee time and responsibilities across segments, partially offset by a $2.5 million increase in compensation paid to certain key employees.
Securities Segment
Payroll and payroll-related expense for the securities segment was $9.4 million for the nine months ended September 30, 2026, as compared to $5.6 million for the same period in 2025, an increase of $3.8 million, or 67.9%, primarily due to a $2.5 million increase in compensation paid to certain key employees and increased compensation to other employees.
Advertising and Marketing Expense
Advertising and marketing expense was $1.9 million for the nine months ended September 30, 2026, as compared to $1.5 million for the same period in 2025, an increase of $0.4 million, or 26.7%, which was not material for the periods presented.
Gain on Sale of Assets
Gain on sale of assets was $1.7 million for the nine months ended September 30, 2026, due to the conveyance of working interests in certain of our operated oil and gas properties, with no comparable activity during the same period in 2025.
Impairment Expense
Impairment expense was $2.1 million for the nine months ended September 30, 2026, as compared to $2.5 million for the same period in 2025, a decrease of $0.4 million, or 16.0%, primarily due to a decrease in lease expirations and title defects within the mineral and non-operating segment.
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Other Expenses
Interest Expense, Net
Interest expense, net, was $172.4 million for the nine months ended September 30, 2026, as compared to $111.7 million for the same period in 2025, an increase of $60.7 million, or 54.3%. The increase was primarily due to (i) a $39.5 million increase in interest on our debt securities, as the principal outstanding increased from $1.0 billion at September 30, 2025 to $1.4 billion at September 30, 2026, with no significant change in the weighted-average interest rate, as our lower-rate Phoenix Flex Notes, first issued in July 2026, represented 1.1% of our total debt outstanding at September 30, 2026; (ii) an $18.6 million increase in interest under the Fortress Credit Agreement; and (iii) a $4.4 million increase in amortization of debt issuance costs related to our debt securities. These increases were partially offset by a $1.8 million increase in capitalized interest primarily due to higher qualifying asset expenditures for the nine months ended September 30, 2026.
Gain (Loss) on Derivatives
Loss on derivatives was $265.0 million for the nine months ended September 30, 2026, as compared to a gain on derivatives of $12.9 million for the same period in 2025, a change of $277.9 million, primarily attributable to a $174.0 million increase in unrealized losses as a result of unfavorable changes in the mark-to-market value of our outstanding commodity derivatives and a $103.9 million increase in realized losses, representing net cash settlements paid on matured contracts during the nine months ended September 30, 2026 as compared to the same period in 2025.
Loss on Debt Extinguishments
Loss on debt extinguishments was $2.6 million for the nine months ended September 30, 2026, as compared to $1.9 million for the same period in 2025, an increase of $0.7 million, or 36.8%. The increase was primarily due to increased write-offs of debt issuance costs associated with the redemption of bonds issued pursuant to our debt offerings, of which $21.0 million of bonds were redeemed during the nine months ended September 30, 2026, as compared to $12.4 million of bonds redeemed for the same period in 2025.
The following table summarizes the par value of bonds redeemed for the periods indicated:
|
|
Nine Months Ended September 30, |
|
|
Change |
|
||||||||||
(in thousands) |
|
2026 |
|
|
2025 |
|
|
$ |
|
|
% |
|
||||
Reg D Bonds |
|
|
|
|
|
|
|
|
|
|
|
|
||||
August 2023 506(c) Bonds |
|
$ |
13,689 |
|
|
$ |
7,391 |
|
|
$ |
6,298 |
|
|
|
85.2 |
% |
Senior Reg D Bonds |
|
|
100 |
|
|
|
500 |
|
|
|
(400 |
) |
|
|
(80.0 |
)% |
December 2022 506(c) Bonds |
|
|
1,447 |
|
|
|
489 |
|
|
|
958 |
|
|
|
195.9 |
% |
Total Reg D Bonds |
|
|
15,236 |
|
|
|
8,380 |
|
|
|
6,856 |
|
|
|
81.8 |
% |
Reg A Bonds |
|
|
840 |
|
|
|
1,575 |
|
|
|
(735 |
) |
|
|
(46.7 |
)% |
Adamantium Bonds |
|
|
3,024 |
|
|
|
2,405 |
|
|
|
619 |
|
|
|
25.7 |
% |
Registered Notes |
|
|
662 |
|
|
|
15 |
|
|
|
647 |
|
|
|
4,313.3 |
% |
Exchange Notes |
|
|
1,226 |
|
|
|
— |
|
|
|
1,226 |
|
|
NM |
|
|
Total |
|
$ |
20,988 |
|
|
$ |
12,375 |
|
|
$ |
8,613 |
|
|
|
69.6 |
% |
NM – not meaningful.
Non-GAAP Financial Measures
Our management uses EBITDA and Adjusted EBITDA to understand and compare our operating results across accounting periods, for internal budgeting and forecasting purposes, and to evaluate financial performance, in each case, without regard to financing methods, capital structure, or historical cost basis. Adjusted EBITDA is also used to understand and compare our results across accounting periods without giving effect to unsettled gains and losses on open commodity derivative contracts. Each of EBITDA and Adjusted EBITDA is presented as supplemental disclosure as we believe it provides useful information to investors and others in understanding and evaluating our results and prospects period over period, including as compared to results of other companies. By providing these non-GAAP financial measures, together with a reconciliation to GAAP results, we believe we are enhancing investors’ understanding of our business and our operating performance, as well as assisting investors in evaluating how well we are executing strategic initiatives.
Each of EBITDA and Adjusted EBITDA has important limitations as an analytical tool because it excludes some, but not all, items that affect net income (loss), the most directly comparable GAAP measure. In particular, each of EBITDA and Adjusted EBITDA excludes certain material costs, such as interest expense, and certain non-cash charges, such as depreciation, depletion, and amortization expense, which have been necessary elements of our expenses. Adjusted EBITDA further excludes non-cash charges related to unsettled gains and losses on open commodity derivative contracts. Because each of EBITDA and Adjusted EBITDA does not account for these expenses, its utility as a measure of our operating performance has material
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limitations. Other companies may not publish this or similar metrics, and our computation of EBITDA and/or Adjusted EBITDA may differ from computations of similarly titled measures of other companies. Therefore, our EBITDA and Adjusted EBITDA should be considered in addition to, and not as a substitute for, in isolation from, or superior to, our financial information prepared in accordance with GAAP, and should be read in conjunction with our condensed consolidated financial statements and the related notes included elsewhere in this Quarterly Report.
The following tables show a reconciliation of EBITDA and Adjusted EBITDA to net income (loss), the most comparable GAAP measure, as presented on the condensed consolidated statements of operations for the periods presented:
|
|
Three Months Ended September 30, |
|
|
Change |
|
||||||||||
(in thousands) |
|
2026 |
|
|
2025 |
|
|
$ |
|
|
% |
|
||||
Net income (loss) |
|
$ |
(1,404 |
) |
|
$ |
8,488 |
|
|
$ |
(9,892 |
) |
|
|
(116.5 |
)% |
Interest income |
|
|
(324 |
) |
|
|
(303 |
) |
|
|
(21 |
) |
|
|
(6.9 |
)% |
Interest expense, net |
|
|
61,575 |
|
|
|
38,816 |
|
|
|
22,759 |
|
|
|
58.6 |
% |
Depreciation, depletion, and amortization |
|
|
88,743 |
|
|
|
45,550 |
|
|
|
43,193 |
|
|
|
94.8 |
% |
EBITDA |
|
|
148,590 |
|
|
|
92,551 |
|
|
|
56,039 |
|
|
|
60.5 |
% |
Unrealized (gain) loss on derivatives |
|
|
59,183 |
|
|
|
(3,645 |
) |
|
|
62,828 |
|
|
|
1,723.7 |
% |
Adjusted EBITDA |
|
$ |
207,773 |
|
|
$ |
88,906 |
|
|
$ |
118,867 |
|
|
|
133.7 |
% |
|
|
Nine Months Ended September 30, |
|
|
Change |
|
||||||||||
(in thousands) |
|
2026 |
|
|
2025 |
|
|
$ |
|
|
% |
|
||||
Net income (loss) |
|
$ |
(35,538 |
) |
|
$ |
32,785 |
|
|
$ |
(68,323 |
) |
|
|
(208.4 |
)% |
Interest income |
|
|
(712 |
) |
|
|
(1,355 |
) |
|
|
643 |
|
|
|
47.5 |
% |
Interest expense, net |
|
|
172,414 |
|
|
|
111,690 |
|
|
|
60,724 |
|
|
|
54.4 |
% |
Depreciation, depletion, and amortization |
|
|
223,245 |
|
|
|
113,392 |
|
|
|
109,853 |
|
|
|
96.9 |
% |
EBITDA |
|
|
359,409 |
|
|
|
256,512 |
|
|
|
102,897 |
|
|
|
40.1 |
% |
Unrealized (gain) loss on derivatives |
|
|
159,843 |
|
|
|
(14,113 |
) |
|
|
173,956 |
|
|
|
1,232.6 |
% |
Adjusted EBITDA |
|
$ |
519,252 |
|
|
$ |
242,399 |
|
|
$ |
276,853 |
|
|
|
114.2 |
% |
EBITDA was $148.6 million for the three months ended September 30, 2026 as compared to $92.6 million for the three months ended September 30, 2025, an increase of $56.0 million, or 60.5%. The increase in EBITDA was primarily driven by a $271.4 million increase in consolidated revenues, partially offset by a $126.0 million increase in operating expense (excluding depreciation, depletion, and amortization expense), primarily driven by purchased crude oil expenses and increased cost of sales, and an $89.9 million increase in loss on derivatives as a result of net cash settlements on matured contracts and unfavorable changes in the mark-to-market value of our outstanding commodity derivatives as of September 30, 2026. Adjusted EBITDA, which excludes unrealized gains and losses on derivatives, was $207.8 million for the three months ended September 30, 2026 as compared to $88.9 million for the three months ended September 30, 2025, an increase of $118.9 million, or 133.7%. Unrealized loss on derivatives increased by $62.8 million due to unfavorable mark-to-market changes in our open commodity derivative contracts.
EBITDA was $359.4 million for the nine months ended September 30, 2026 as compared to $256.5 million for the nine months ended September 30, 2025, an increase of $102.9 million, or 40.1%. The increase in EBITDA was primarily driven by a $696.3 million increase in consolidated revenues, partially offset by a $314.8 million increase in operating expense (excluding depreciation, depletion, and amortization expense), primarily driven by purchased crude oil expenses and increased cost of sales, and a $277.9 million increase in loss on derivatives as a result of net cash settlements on matured contracts and unfavorable changes in the mark-to-market value of our outstanding commodity derivatives as of September 30, 2026. Adjusted EBITDA, which excludes unrealized gains and losses on derivatives, was $519.3 million for the nine months ended September 30, 2026 as compared to $242.4 million for the nine months ended September 30, 2025, an increase of $276.9 million, or 114.2%. Unrealized loss on derivatives increased by $174.0 million due to unfavorable mark-to-market changes in our open commodity derivative contracts.
41
Table of Contents
The following table shows a reconciliation of EBITDA and Adjusted EBITDA to net income (loss), the most comparable GAAP measure, for the years ended December 31, 2025, 2024, and 2023:
|
|
Year Ended December 31, |
|
|||||||||
(in thousands) |
|
2025 |
|
|
2024 |
|
|
2023 |
|
|||
Net income (loss) |
|
$ |
66,108 |
|
|
$ |
(24,793 |
) |
|
$ |
(16,189 |
) |
Interest income |
|
|
(1,653 |
) |
|
|
(705 |
) |
|
|
(66 |
) |
Interest expense, net |
|
|
161,214 |
|
|
|
90,210 |
|
|
|
47,882 |
|
Depreciation, depletion, and amortization |
|
|
177,913 |
|
|
|
85,977 |
|
|
|
34,228 |
|
EBITDA |
|
|
403,582 |
|
|
|
150,689 |
|
|
|
65,855 |
|
Unrealized (gain) loss on derivatives |
|
|
(48,289 |
) |
|
|
7,518 |
|
|
|
32 |
|
Adjusted EBITDA |
|
$ |
355,293 |
|
|
$ |
158,207 |
|
|
$ |
65,887 |
|
Liquidity and Capital Resources
Overview
Our primary sources of liquidity to date have been cash flows from operations, borrowings under credit facilities, issuances of debt securities, and the issuance of the Series A Preferred Shares in September 2025. Future sources of liquidity may also include other credit facilities, continued issuances of debt or equity securities, which may be different than the type of debt or equity securities we have issued so far in terms of security, maturity, and interest rates, asset-backed or other securitizations, and capital contributions. Our primary uses of cash are on the development and operation of PhoenixOp’s properties, the acquisition of mineral and royalty interests, lease operating expenses, and our proportionate share of production and ad valorem taxes for mineral and royalty interests, production costs, including gathering, processing, and transportation costs, debt service payments and distributions on the Series A Preferred Shares, the reduction of outstanding debt balances, and general overhead and other corporate expenses. As we continue to engage in increased drilling and direct production activities through PhoenixOp, we expect the development and operation of PhoenixOp’s properties to become an increasingly significant use of our cash. As of September 30, 2026, we had cash and cash equivalents of $113.9 million, outstanding indebtedness of $2.0 billion, and a liquidation preference of Series A Preferred Shares of $67.6 million.
As of September 30, 2026, $205.9 million of our debt was classified as current, including $17.6 million of Phoenix Flex Notes maturing after September 30, 2027, for which holders may require us to redeem within the next 12 months under the notes’ put features. In addition, $179.3 million of interest is expected to accrue on our outstanding debt, and we expect to make $6.8 million of distributions on our Series A Preferred Shares over the next 12 months. Over the same period, we expect to drill between 70 and 110 gross and 55.0 and 86.0 net wells across our operated leasehold acreage in the Bakken/Williston Basin in North Dakota and Montana and the Powder River Basin in Wyoming, and expect to participate in the drilling of between 230 and 330 gross and 5.3 and 7.6 net wells across our non-operated leasehold. We estimate that these direct drilling operations and non-operated activity will require between $1.0 billion and $1.1 billion of capital expenditures.
Our ability to finance our operations, including funding capital expenditures and acquisitions, meeting our indebtedness obligations, making distributions on the Series A Preferred Shares, or refinancing our indebtedness, will depend on our ability to generate cash in the future. We raised $536.7 million in proceeds from the issuance of debt securities and increased borrowings under the Fortress Credit Agreement during the nine months ended September 30, 2026. We believe that these sources of liquidity will be sufficient to meet our cash requirements, with respect to our current commitments, including normal operating needs, debt service obligations, and capital expenditures, for at least the next 12 months, and will allow us to continue to execute on our strategy of expanding our direct drilling operations through PhoenixOp and acquiring attractive mineral and royalty interests in order to position us to grow our cash flows.
We periodically assess changes in current and projected cash flows, acquisition and divestiture activities, and other factors to determine the effects on our liquidity. Our ability to generate cash is subject to a number of factors, many of which are beyond our control, including commodity prices, weather, and general economic, financial, competitive, legislative, regulatory, and other factors.
Commodity prices have been volatile during 2026. Following the onset of the conflict in the Middle East involving Iran, Israel, the United States, and other countries in the region, and the closure of the Strait of Hormuz, NYMEX WTI crude oil prices rose sharply, reaching $112.95 per Bbl on April 7, 2026. During the third quarter, oil prices ranged from a low of $69.60 per Bbl on July 6, 2026 to a high of $107.02 per Bbl on September 15, 2026. We continue to monitor our drilling operations and production plans in light of this volatility. Although we believe we are well positioned to operate in a lower-price environment, a prolonged period of commodity prices below those assumed in our business plan would reduce our cash flows from operations. In that event, we may adjust our business plan by, among other actions, reducing capital expenditures, slowing drilling activity, or reducing planned production. We may also be required to raise additional capital, above our current expectations, in order to fully realize our current or adjusted business plan. If cash flow from operations does not meet our
42
Table of Contents
expectations, we may reduce our expected level of capital expenditures. If we require additional capital for acquisitions or other reasons, we may raise such capital through additional borrowings, asset sales, offerings of equity and debt securities, or other means. We cannot assure you that necessary capital will be available on acceptable terms or at all. Our ability to raise funds through the incurrence of additional indebtedness could be limited by covenants in our debt arrangements. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that are favorable to us or finance the capital expenditures necessary to maintain our production or proved reserves. See “Risks Related to Our Business and Operations” and “Risks Related to Our Indebtedness” in Part I, Item 1A of our 2025 Annual Report.
We or our affiliates may from time to time seek to repurchase or retire Registered Notes, the Phoenix Flex Notes, our other indebtedness, or Series A Preferred Shares through cash purchases and/or exchanges for equity or debt securities, in open-market purchases, privately negotiated transactions, tender or exchange offers, or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity, contractual restrictions, and other factors. The amounts involved may be material. For more information regarding the material terms of our outstanding indebtedness, see “—Indebtedness” below.
Cash Flows
The following table summarizes our cash flows for the periods indicated:
|
|
Nine Months Ended September 30, |
|
|
Change |
|
||||||||||
(in thousands) |
|
2026 |
|
|
2025 |
|
|
$ |
|
|
% |
|
||||
Net cash provided by (used in): |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Operating activities |
|
$ |
489,015 |
|
|
$ |
204,692 |
|
|
$ |
284,323 |
|
|
|
138.9 |
% |
Investing activities |
|
|
(848,576 |
) |
|
|
(620,115 |
) |
|
|
(228,461 |
) |
|
|
(36.8 |
)% |
Financing activities |
|
|
407,694 |
|
|
|
390,061 |
|
|
|
17,633 |
|
|
|
4.5 |
% |
Net increase (decrease) in cash and cash equivalents |
|
$ |
48,133 |
|
|
$ |
(25,362 |
) |
|
$ |
73,495 |
|
|
|
289.8 |
% |
Operating Activities
Net cash provided by operating activities for the nine months ended September 30, 2026 was $489.0 million, as compared to $204.7 million for the same period in 2025, an increase of $284.3 million in cash provided by operating activities. The increase was primarily driven by a $307.5 million increase in non-cash charges, primarily resulting from changes in the unrealized loss on derivatives, depreciation, depletion, and amortization, noncash stated interest, and the amortization of debt discount and debt issuance costs, and $45.1 million of favorable changes in operating assets and liabilities, partially offset by a $68.3 million change from net income to net loss.
The $45.1 million of favorable fluctuations in operating assets and liabilities were primarily attributable to a $66.6 million increase in other current liabilities and accrued expenses, a $13.3 million favorable change in accrued settlements on our derivative contracts, and a $7.8 million decrease in escrow, partially offset by unfavorable fluctuations attributable to a $21.2 million increase in accounts receivable, a $10.2 million decrease in accounts payable primarily due to the timing of cash receipts and payments, a $9.8 million increase in other operating activities, and a $1.4 million increase in accrued interest.
Investing Activities
Net cash used in investing activities for the nine months ended September 30, 2026 was $848.6 million, as compared to $620.1 million for the same period in 2025, an increase of $228.5 million in cash used in investing activities. The increase was driven by a $245.8 million increase in additions to oil and gas properties, primarily due to increased drilling and completion activities, partially offset by an $18.2 million increase in proceeds from the sale of assets in our operating segment during the nine months ended September 30, 2026 as compared to the same period in 2025.
Financing Activities
Net cash provided by financing activities for the nine months ended September 30, 2026 was $407.7 million, as compared to $390.1 million for the same period in 2025, an increase of $17.6 million in cash provided by financing activities, primarily driven by increased proceeds from issuances of debt, net of debt discount, of $82.6 million and a $0.1 million decrease in payments of debt issuance costs, partially offset by a $47.9 million decrease in proceeds from preferred equity offering, net of issuance costs, an $8.6 million increase in repayments of debt related to securities, a $5.1 million increase in payments of dividends for the Series A Preferred Shares, and a $3.6 million increase in payments of deferred closings associated with mineral interest acquisitions.
Preferred Equity
In September 2025, we completed our offering of the Series A Preferred Shares, which shares were listed on the NYSE American under the ticker symbol PHXE.P and commenced trading on September 30, 2025. We sold an aggregate of 2,704,023
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Series A Preferred Shares at closing, which represented $67.6 million in initial liquidation preference at a public offering price of $20.00 per share for gross proceeds of $54.1 million. Offering costs of $6.2 million were recorded as a reduction of the gross proceeds. In addition, at issuance we recorded a $2.4 million discount associated with the stepped distribution rate feature of the Series A Preferred Shares, which provides for increases in the distribution rate prior to the commencement of the 11.0% perpetual distribution rate in year five. For the three and nine months ended September 30, 2026, $0.2 million and $0.5 million of this discount was amortized, respectively.
During the three and nine months ended September 30, 2026, we paid $1.7 million and $5.1 million, respectively, of distributions to the holders of the Series A Preferred Shares equal to $0.625 per share and $1.875 per share, respectively. In September 2026, our Board of Directors authorized and declared a distribution on the Series A Preferred Shares equal to $0.625 per share, which was paid on October 15, 2026, to holders of record as of October 1, 2026, and totaled $1.7 million. As of September 30, 2026, we accrued $1.5 million of dividends payable, which is included in other current liabilities on the condensed consolidated balance sheet.
Indebtedness
Set forth below is a chart of our outstanding third-party indebtedness as of September 30, 2026 (dollars in thousands):
Indebtedness |
|
Offering Commencement |
|
Principal Amount Outstanding |
|
|
Term |
|
Earliest |
|
|
Latest |
|
Interest Rate |
|
|||
Secured |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Fortress Credit Agreement(1) |
|
N/A |
|
$ |
600,000 |
|
|
3 years |
|
|
— |
|
|
10/27/2028 |
|
Term SOFR + 7.10% |
|
|
Adamantium Secured Note(2) |
|
N/A |
|
|
9,300 |
|
|
7 years |
|
|
— |
|
|
11/1/2031 |
|
|
16.5 |
% |
Phoenix Flex Notes(3): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Three-Month Phoenix Flex Notes |
|
7/7/2026 |
|
|
8,037 |
|
|
10 years |
|
7/9/2036 |
|
|
9/24/2036 |
|
|
6.0 |
% |
|
Six-Month Phoenix Flex Notes |
|
7/7/2026 |
|
|
6,465 |
|
|
10 years |
|
7/9/2036 |
|
|
9/24/2036 |
|
|
6.3 |
% |
|
Nine-Month Phoenix Flex Notes |
|
7/7/2026 |
|
|
1,361 |
|
|
10 years |
|
7/9/2036 |
|
|
9/24/2036 |
|
|
6.5 |
% |
|
Twelve-Month Phoenix Flex Notes |
|
7/7/2026 |
|
|
1,780 |
|
|
10 years |
|
7/9/2036 |
|
|
9/24/2036 |
|
|
6.8 |
% |
|
Eighteen-Month Phoenix Flex Notes |
|
7/7/2026 |
|
|
4,735 |
|
|
10 years |
|
7/9/2036 |
|
|
9/24/2036 |
|
|
7.0 |
% |
|
Total Phoenix Flex Notes |
|
|
|
|
22,378 |
|
|
|
|
|
|
|
|
|
|
|
||
Total Secured Debt |
|
|
|
|
631,678 |
|
|
|
|
|
|
|
|
|
|
|
||
Unsecured |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Reg A Bonds(4) |
|
12/23/2021 |
|
|
22,359 |
|
|
3 years |
|
10/10/2026 |
|
|
8/10/2027 |
|
|
9.0 |
% |
|
Senior Reg D Bonds(5) |
|
7/20/2022 |
|
|
7,504 |
|
|
5 years |
|
7/31/2027 |
|
|
12/31/2027 |
|
|
11.0 |
% |
|
December 2022 506(c) Bonds(6): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Series C |
|
12/22/2022 |
|
|
8,835 |
|
|
5 years |
|
12/10/2027 |
|
|
8/10/2028 |
|
|
11.0 |
% |
|
Series D |
|
12/22/2022 |
|
|
30,179 |
|
|
7 years |
|
12/10/2029 |
|
|
10/10/2030 |
|
|
12.0 |
% |
|
August 2023 506(c) Bonds(6): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Series U, AA, and FF |
|
8/29/2023 |
|
|
130,872 |
|
|
1 year |
|
10/10/2026 |
|
|
9/10/2027 |
|
9.0% - 10.0% |
|
||
Series V, BB, and GG |
|
8/29/2023 |
|
|
140,569 |
|
|
3 years |
|
10/10/2026 |
|
|
9/10/2029 |
|
10.0% - 11.0% |
|
||
Series W, CC, and HH |
|
8/29/2023 |
|
|
91,675 |
|
|
5 years |
|
8/10/2028 |
|
|
9/10/2031 |
|
11.0% - 12.0% |
|
||
Series X, DD, and II |
|
8/29/2023 |
|
|
106,489 |
|
|
7 years |
|
9/10/2030 |
|
|
9/10/2033 |
|
12.0% - 13.0% |
|
||
Series Y |
|
8/29/2023 |
|
|
2,890 |
|
|
9 years |
|
9/10/2032 |
|
|
9/10/2033 |
|
|
12.5 |
% |
|
Series Z, EE, and JJ |
|
8/29/2023 |
|
|
383,405 |
|
|
11 years |
|
9/10/2034 |
|
|
9/10/2037 |
|
13.0% - 14.0% |
|
||
Total Reg D/Reg A Bonds |
|
|
|
|
924,777 |
|
|
|
|
|
|
|
|
|
|
|
||
Exchange Notes(4): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Three-Year Exchange Notes |
|
5/15/2025 |
|
|
4,942 |
|
|
3 years |
|
12/10/2027 |
|
|
5/10/2029 |
|
|
9.0 |
% |
|
Five-Year Exchange Notes |
|
5/15/2025 |
|
|
8,363 |
|
|
5 years |
|
12/10/2029 |
|
|
4/10/2031 |
|
|
10.0 |
% |
|
Seven-Year Exchange Notes |
|
5/15/2025 |
|
|
4,448 |
|
|
7 years |
|
12/10/2031 |
|
|
3/10/2033 |
|
|
11.0 |
% |
|
Eleven-Year Exchange Notes |
|
5/15/2025 |
|
|
15,868 |
|
|
11 years |
|
5/10/2036 |
|
|
4/10/2037 |
|
|
12.0 |
% |
|
Total Exchange Notes |
|
|
|
|
33,621 |
|
|
|
|
|
|
|
|
|
|
|
||
Registered Notes(7): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Three-Year Registered Notes |
|
5/14/2025 |
|
|
30,265 |
|
|
3 years |
|
5/10/2028 |
|
|
9/10/2029 |
|
|
9.0 |
% |
|
Five-Year Registered Notes |
|
5/14/2025 |
|
|
19,331 |
|
|
5 years |
|
5/10/2030 |
|
|
9/10/2031 |
|
|
10.0 |
% |
|
Seven-Year Registered Notes |
|
5/14/2025 |
|
|
9,547 |
|
|
7 years |
|
5/10/2032 |
|
|
9/10/2033 |
|
|
11.0 |
% |
|
Eleven-Year Registered Notes |
|
5/14/2025 |
|
|
37,987 |
|
|
11 years |
|
5/10/2036 |
|
|
9/10/2037 |
|
|
12.0 |
% |
|
Total Registered Notes |
|
|
|
|
97,130 |
|
|
|
|
|
|
|
|
|
|
|
||
Adamantium Bonds(8) |
|
9/29/2023 |
|
|
343,366 |
|
|
5-11 years |
|
6/10/2029 |
|
|
9/10/2037 |
|
13.0% - 16.0% |
|
||
Total Unsecured Debt |
|
|
|
|
1,398,894 |
|
|
|
|
|
|
|
|
|
|
|
||
Total Debt |
|
|
|
$ |
2,030,572 |
|
|
|
|
|
|
|
|
|
|
|
||
44
Table of Contents
Fortress Credit Agreement
In August 2024, we entered into the Fortress Credit Agreement with Fortress as lender and administrative agent, which was subsequently amended to add additional term loan tranches and syndicated to include an additional institutional lender. In February 2026, the Fortress Credit Agreement was further amended to provide a $75.0 million term loan funded at closing and up to $225.0 million in remaining commitments available on a discretionary basis. This amendment also revised the mandatory repayment schedule such that $262.5 million, plus 50.0% of the aggregate principal amount of delayed draw term loans borrowed after February 2026, is due on October 31, 2027. In June 2026, the Fortress Credit Agreement was further amended to, among other things, permit the issuance of the Phoenix Flex Notes. In August 2026, the Fortress Credit Agreement was further amended to provide a $75.0 million term loan funded at closing, with up to $150.0 million in remaining commitments available on a discretionary basis. Proceeds are to be used to finance the development of our oil and gas properties in accordance with the approved plan of development provided in the Fortress Credit Agreement.
As of September 30, 2026, we had $600.0 million of aggregate principal outstanding under the Fortress Term Loans. The outstanding principal, excluding the contingent principal obligations as described below, must be repaid as follows: (i) on October 31, 2027, $300.0 million, less the aggregate amount of all voluntary and mandatory prepayments made through that date; and (ii) the remaining outstanding principal on October 27, 2028.
The Fortress Term Loans are subject to 3.00% of OID. The Fortress Credit Agreement also provides for an $8.5 million and $6.5 million tranche of loans which are rebated if certain conditions are met, and therefore represent contingent principal obligations that are only due and payable (together with accrued interest thereon) upon the occurrence of those conditions, including payment defaults under the Fortress Credit Agreement or a bankruptcy filing. We expect these to be rebated in full. The all-in interest rate for the Fortress Term Loans was 10.8% and 11.1% at September 30, 2026 and December 31, 2025, respectively.
The Fortress Credit Agreement contains various customary covenants, including financial covenants that require us to maintain ratios around our maximum total secured leverage, minimum asset coverage, current assets to current liabilities, and working capital as of the last day of each calendar month or fiscal quarter, as the case may be. On October 21, 2026, subsequent to the balance sheet date, pursuant to Amendment No. 11, we obtained a waiver of noncompliance with our current ratio covenant for the calendar month ended September 30, 2026, which resulted primarily from the timing of accelerated well completion expenditures undertaken to capitalize on higher commodity prices. Amendment No. 11 also permits us to issue the Phoenix Access Notes, subject to the conditions and limitations described in the Fortress Credit Agreement.
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Table of Contents
Adamantium Securities
In September 2023, we entered into the Adamantium Loan Agreement with Adamantium, as lender, which was amended in October 2023 to add PhoenixOp as a borrower, and subsequently amended to increase the loan amount under the agreement. The Adamantium Loan Agreement provides for up to $609.3 million in aggregate principal amount of borrowings in one or more advances, comprising $600.0 million from the proceeds of Adamantium Bonds and $9.3 million from the proceeds of the Adamantium Secured Note. We expect to use the proceeds of borrowings under the Adamantium Loan Agreement (i) to purchase mineral rights and non-operated working interests, as well as additional asset acquisitions, (ii) to finance potential drilling and exploration operations of one or more subsidiaries (including PhoenixOp), and (iii) for other working capital needs.
As of September 30, 2026, $343.4 million aggregate principal amount of Adamantium Bonds was outstanding, with maturity dates ranging from five to eleven years from the issue date and interest rates ranging from 13.0% to 16.0% per annum, and $9.3 million aggregate principal amount was outstanding under the Adamantium Secured Note, which initially matures in November 2031, has an interest rate of 16.5% per annum, and is secured by Adamantium’s rights under the Adamantium Loan Agreement.
Registered Notes
In May 2025, the SEC declared effective our registration statement with respect to the continuous offering of up to $750.0 million aggregate principal amount of our Registered Notes with maturity dates ranging from three to eleven years from the issue date and interest rates ranging from 9.0% to 12.0% per annum. As of the date of this Quarterly Report, we had issued $104.3 million aggregate principal amount of Registered Notes. The outstanding Registered Notes mature between May 10, 2028 and September 10, 2037.
Phoenix Flex Notes
In June 2026, we filed a registration statement on Form S-1 with the SEC, which was declared effective in July 2026, with respect to the continuous offering of up to an aggregate principal amount of $100.0 million of Phoenix Flex Notes. The Phoenix Flex Notes comprise senior subordinated junior lien notes that will mature ten years from the date of initial issuance, with interest rates ranging from 6.0% to 7.0% per annum depending on the applicable interval of three, six, nine, twelve, or eighteen months at which holders can request redemption of their Phoenix Flex Notes, with such interest payable either in cash or by adding such interest to the principal amount of such notes.
The Phoenix Flex Notes are our senior subordinated obligations and are secured on a junior basis, equally and ratably with all of our parity lien indebtedness, by mortgages on certain properties as determined by us, which mortgages are junior to the security interest under the Fortress Credit Agreement and other obligations secured on a first-lien priority basis. The indenture governing the Phoenix Flex Notes provides that the aggregate outstanding principal amount of Phoenix Flex Notes may not exceed 100% of the aggregate total discounted present value of the junior mortgages serving as collateral thereunder, after deducting any allocable amount securing any senior-priority secured debt, subject to certain exceptions. In the event the Loan-to-Value Ratio exceeds 1.00 to 1.00 as of any date, the Company may cure such deficiency within 60 days following such date by, among other things, pledging additional collateral, repaying senior-priority secured debt, or repaying a portion of the Phoenix Flex Notes until the Loan-to-Value Ratio is no longer exceeded on a pro forma basis.
In connection with the issuance of the Phoenix Access Notes, the Phoenix Flex Notes will become secured on a junior basis, equally and ratably with the Phoenix Access Notes, the Adamantium Loan Agreement, and any other indebtedness the Company may determine from time to time to be secured on a pari passu basis with the Phoenix Flex Notes, on substantially all of the collateral securing the Fortress Credit Agreement on a first-lien priority basis.
The Phoenix Flex Notes are contractually senior to the Registered Notes and the Subordinated Reg D Bonds and, without giving effect to collateral arrangements, rank equally in right of payment with the Senior Phoenix Bonds, and are effectively senior to those obligations to the extent of the value of the collateral securing the Phoenix Flex Notes. The Phoenix Flex Notes are contractually subordinated to the obligations under the Fortress Credit Agreement, the Adamantium Loan Agreement, and any other debt the Issuer determines to be contractually senior to the Phoenix Flex Notes, and are structurally subordinated to the Adamantium Securities to the extent of the value of Adamantium’s assets, including the collateral securing the Adamantium Loan Agreement.
The Phoenix Flex Notes contain customary events of default and may be redeemed at our option at any time without premium or penalty. Subject to the subordination provisions applicable to the Phoenix Flex Notes, the holders of the Phoenix Flex Notes may request that the Company redeem all or a portion of such holders’ notes on the applicable put date at a price equal to 100% of the aggregate principal amount of such notes, plus accrued and unpaid interest. Subject to the subordination provisions applicable to the Phoenix Flex Notes, holders also have a right to request redemption of their notes at any time prior to maturity at a price equal to 95.0% of the principal amount, plus accrued and unpaid interest, subject to a limit of 10% of the then-outstanding principal amount of the Phoenix Flex Notes in any given calendar year. As of the date of this Quarterly Report,
46
Table of Contents
we had issued $22.5 million aggregate principal amount of Phoenix Flex Notes. The outstanding Phoenix Flex Notes mature between July 9, 2036 and September 24, 2036, and have initial put dates ranging from October 7, 2026 to March 22, 2028.
Phoenix Access Notes
In October 2026, we filed a registration statement on Form S-1 with the SEC relating to the offering, on a continuous basis, of up to $500.0 million aggregate principal amount of Phoenix Access Notes, which will have maturity dates of two, three, five, seven, or eleven years from the date of initial issuance and interest rates ranging from 7.5% to 11.0% per annum. The Phoenix Access Notes will be our senior subordinated obligations and will be secured on a junior basis, equally and ratably with the Adamantium Loan Agreement, the Phoenix Flex Notes, and any other parity lien debt, by substantially all of the collateral securing the Fortress Credit Agreement on a first-lien priority basis. The Phoenix Access Notes will be contractually senior to the Registered Notes and the Subordinated Reg D Bonds and, without giving effect to collateral arrangements, will rank equally in right of payment with the Senior Phoenix Bonds and the Phoenix Flex Notes, and will be effectively senior to our unsecured indebtedness to the extent of the value of the collateral securing the Phoenix Access Notes. The Phoenix Access Notes will be contractually subordinated to the obligations under the Fortress Credit Agreement, the Adamantium Loan Agreement, and any other senior debt, and will be structurally subordinated to the Adamantium Securities to the extent of the value of Adamantium’s assets, including Adamantium’s right to receive payments under the Adamantium Loan Agreement. As of the date of this Quarterly Report, the registration statement had not been declared effective and no Phoenix Access Notes had been issued.
Reg D/Reg A Bonds and Exchange Notes
As of September 30, 2026, we had $958.4 million aggregate principal amount outstanding of unsecured bonds issued pursuant to Regulation D, Regulation A, and Section 3(a)(9) and/or 4(a)(2) of the Securities Act (other than the Adamantium Bonds), consisting of:
(a) $7.5 million aggregate principal amount outstanding of Senior Reg D Bonds, which are unsecured bonds offered and sold pursuant to an offering under Rule 506(c) of Regulation D that commenced in July 2022 and terminated in December 2022, with a maturity date of five years from the issue date and an interest rate of 11.0% per annum, and which are pari passu with the Reg A Bonds and the Exchange Notes, are contractually subordinated to amounts under the Fortress Credit Agreement and the Adamantium Debt, are contractually senior to obligations under the Subordinated Reg D Bonds and the Registered Notes, and, without giving effect to collateral arrangements, rank equally in right of payment with the Phoenix Flex Notes;
(b) $894.9 million aggregate principal amount outstanding of Subordinated Reg D Bonds, which are contractually subordinated to obligations under the Fortress Credit Agreement, the Adamantium Debt, the Reg A Bonds, the Exchange Notes, the Senior Reg D Bonds, the Registered Notes, and the Phoenix Flex Notes, comprising:
(i) $39.0 million aggregate principal amount outstanding of Series C through Series D-1 December 2022 506(c) Bonds, which are unsecured bonds offered and sold pursuant to an offering under Rule 506(c) of Regulation D that commenced in December 2022 and terminated in August 2023, with maturity dates ranging from five to seven years from the issue date and interest rates ranging from 11.0% to 12.0% per annum; and
(ii) $855.9 million aggregate principal amount outstanding of Series U through Series JJ-1 August 2023 506(c) Bonds, which are unsecured bonds offered and sold to date pursuant to an offering under Rule 506(c) of Regulation D that commenced in August 2023 with maturity dates ranging from one to eleven years from the issue date and interest rates ranging from 9.0% to 14.0% per annum;
(c) $22.4 million aggregate principal amount outstanding of Reg A Bonds, which are unsecured bonds offered and sold pursuant to an offering under Regulation A, which commenced in December 2021 and terminated in December 2024, with a term of three years from the issue date and an interest rate of 9.0% per annum, which Reg A Bonds are pari passu with the Senior Reg D Bonds and Exchange Notes, are contractually senior to obligations under the Subordinated Reg D Bonds and the Registered Notes, and, without giving effect to collateral arrangements, rank equally in right of payment with the Phoenix Flex Notes; and
(d) $33.6 million aggregate principal amount outstanding of Exchange Notes, which are unsecured bonds issued by us to holders of the Reg A Bonds in exchange for their Reg A Bonds in offerings exempt from registration under Section 3(a)(9) and/or 4(a)(2) of the Securities Act, with maturity dates of three, five, seven, or eleven years from the issue date and interest rates ranging from 9.0% to 12.0% per annum, which Exchange Notes are pari passu with the Senior Reg D Bonds and Reg A Bonds, are contractually senior to obligations under the Subordinated Reg D Bonds and the Registered Notes, are contractually subordinated to obligations under the Fortress Credit Agreement and the Adamantium Debt, and, without giving effect to collateral arrangements, rank equally in right of payment with the Phoenix Flex Notes.
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Table of Contents
Contractual Obligations and Commitments
As part of our ongoing operations, we enter into contractual arrangements that obligate us to make future cash payments. These obligations impact our liquidity and capital resource needs. Our estimated future obligations consist of debt obligations, interest on debt obligations, leases, deferred closing arrangements, purchase obligations, and delivery commitments.
A summary of our commitments is described in Note 13, “Commitments and Contingencies,” of the notes to the accompanying condensed consolidated financial statements included elsewhere in this Quarterly Report.
Other than the items described in Note 13, as of September 30, 2026, there were no other material changes outside the ordinary course of business since December 31, 2025 to our contractual obligations and commitments and the related cash requirements.
Critical Accounting Policies and Use of Estimates
Our critical accounting policies are described in Note 2, “Significant Accounting Policies,” of the notes to the accompanying condensed consolidated financial statements included elsewhere in this Quarterly Report. During the nine months ended September 30, 2026, there have been no material changes in our critical accounting policies from those discussed under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Use of Estimates” in our 2025 Annual Report except as discussed below.
Inventory
Crude oil in storage tanks that has not yet been sold is classified as inventory and recorded within other current assets on our condensed consolidated balance sheets. Inventory is stated at the lower of cost and net realizable value, with cost determined using a weighted average cost method, and includes costs incurred to bring the inventory to its present location and condition.
Oil and Gas Properties
We account for crude oil, natural gas, and NGL exploration and development activities using the successful efforts method of accounting. Under this method, costs to acquire, drill, and complete development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. Exploration costs, including geological and geophysical expenses and delay rentals for oil and gas leases, are expensed as incurred. Costs of drilling exploratory wells are initially capitalized but expensed if the well is determined to be unsuccessful. All capitalized well costs and leasehold costs of proved properties are depleted on a unit-of-production basis over the remaining life of proved developed reserves and total proved reserves, respectively, related to a geologic basin.
Recent Accounting Pronouncements
See Note 2, “Significant Accounting Policies,” of the notes to the accompanying condensed consolidated financial statements included elsewhere in this Quarterly Report, for recently adopted accounting pronouncements and recent accounting pronouncements not yet adopted, if any.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates or from counterparty and customer credit risk, each as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. 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. All of our instruments that are sensitive to market risk were entered into for purposes other than speculative trading.
Commodity Price Risk
Our major market risk exposure is in the pricing applicable to the oil, natural gas, and NGL production of our E&P operators, including PhoenixOp, which affects our revenue from PhoenixOp and the royalty payments we receive from our other E&P operators. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for oil, natural gas, and NGL has been volatile and unpredictable for several years, and this volatility is expected to continue in the future. The prices that our E&P operators receive for oil, natural gas, and NGL production depend on many factors outside of their and our control, such as the strength of the global economy and global supply and demand for the commodities they produce.
To reduce the impact of fluctuations in oil, natural gas, and NGL prices on our revenues, we may periodically enter into commodity derivative contracts with respect to certain of our oil, natural gas, and NGL production through various transactions that limit the risks of fluctuations of future prices. Additionally, we are required to hedge a portion of anticipated oil production pursuant to certain covenants under the Fortress Credit Agreement. As of September 30, 2026, over approximately the next
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Table of Contents
three years through June 2029, we had 14.6 million Bbl of anticipated oil production hedged through a combination of fixed-price swaps at a weighted average contract price of $61.80 per Bbl, collars with weighted average floor and ceiling prices of $55.05 and $70.29 per Bbl, respectively, and purchased put options with a strike price of $65.00 per Bbl. In addition, we have purchased call options with a strike price of $75.00 per Bbl on 8.8 million Bbl of the volumes covered by our fixed-price swaps, which allow us to participate in price increases above $75.00 per Bbl on those volumes. Option strike prices exclude the effect of deferred option premiums. Assuming a price of $0 per Bbl, these derivative contracts would generate aggregate cash settlements, net of approximately $59.7 million of deferred option premiums, of approximately $856.7 million over the same period. We plan to continue our practice of entering into such transactions to reduce the impact of commodity price volatility on our net cash provided by operating activities. Future transactions may include additional price swaps, whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty, or collars, whereby we would receive the excess, if any, of the fixed floor over the floating rate or pay the excess, if any, of the floating rate over the fixed ceiling. These hedging activities are intended to limit our exposure to product price volatility.
By using derivative instruments to economically limit exposure to changes in commodity prices, we expose ourselves to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes us, which creates credit risk. See “—Counterparty and Customer Credit Risk” below.
The fair market value of our commodity derivative contracts was a net liability of $129.9 million as of September 30, 2026. Based upon our open commodity derivative positions at September 30, 2026, a hypothetical 10.0% increase in the NYMEX WTI price would increase our net derivative liability position by $70.4 million, while a 10.0% decrease in the NYMEX WTI price would decrease our net derivative liability position by $71.9 million.
A $1.00 per Bbl change in our realized oil price would have resulted in a $9.7 million and a $5.7 million change in our oil revenues for the nine months ended September 30, 2026 and 2025, respectively. A $0.10 per Mcf change in our realized natural gas price would have resulted in a $0.4 million and a $0.2 million change in our natural gas revenues for the nine months ended September 30, 2026 and 2025, respectively. A $1.00 per Bbl change in NGL prices would have resulted in a $0.9 million and a $0.4 million change in our NGL revenues for the nine months ended September 30, 2026 and 2025, respectively. Revenues from oil sales contributed 95.6% and 95.1%, revenues from natural gas sales contributed 0.9% and 1.2%, for the nine months ended September 30, 2026 and 2025, respectively, and revenues from NGL sales contributed 1.8% of our consolidated revenues for both the nine months ended September 30, 2026 and 2025.
Interest Rate Risk
Our primary exposure to interest rate risk results from outstanding borrowings under our credit facilities, which bear interest at a floating rate. The average interest rate incurred when such facility was outstanding on our borrowings under the Fortress Credit Agreement during the nine months ended September 30, 2026 and 2025 was 10.8% and 11.4%, respectively. Assuming no change in the amount of borrowings under the Fortress Credit Agreement outstanding, a hypothetical 100 basis point increase or decrease in the average interest rate under these borrowings would increase or decrease our interest expense on those borrowings on an annual basis by approximately $6.0 million. See “—Liquidity and Capital Resources—Indebtedness—Fortress Credit Agreement.”
Counterparty and Customer Credit Risk
We often maintain cash balances in excess of the federally insured limits, which may subject us to concentrations of credit risk. We manage this risk by maintaining deposits with a financial institution that we believe to be creditworthy and by monitoring its financial condition on an ongoing basis.
Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties. We evaluate the credit standing of such counterparties as we deem appropriate. We have determined that our counterparties have an acceptable credit risk for the size of derivative position placed; therefore, we do not require collateral or other security from our counterparties. Additionally, we use master netting arrangements to minimize credit risk exposure.
Our principal exposures to credit risk are through receivables generated by product sales from the delivery of commodities that we extract and deliver to purchasers and the production activities of our operators. For the three months ended September 30, 2026, one purchaser of our commodities and eight third-party E&P operators made up 39.7% and 11.6% of our consolidated revenue, respectively, as compared to three purchasers of our commodities and thirteen third-party E&P operators that made up 49.0% and 14.0% of our consolidated revenue, respectively, for the three months ended September 30, 2025. For the nine months ended September 30, 2026, one purchaser of our commodities and twelve third-party E&P operators made up 42.5% and 11.1% of our consolidated revenue, respectively, as compared to three purchasers of our commodities and twelve third-party E&P operators that made up 54.0% and 16.0% of our consolidated revenue, respectively, for the nine months ended September 30, 2025.
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Similarly, as of September 30, 2026, we had concentrations in accounts receivable of 13.7% and 10.8% with two purchasers of our commodities and 10.9% with one third-party E&P operator, as compared to 13.0% with one purchaser of our commodities and 13.0% with one third-party E&P operator as of December 31, 2025. Although we are exposed to a concentration of credit risk due to our reliance on operators and purchasers of our commodities, we do not believe the loss of any single counterparty would materially impact our operating results as crude oil and natural gas are fungible products with well-established markets and numerous participants. If multiple purchasers were to cease making purchases at or around the same time, we believe there would be challenges initially, but there would be ample markets to handle the disruption. Additionally, recent rulings in bankruptcy cases involving our third-party E&P operators have stipulated that royalty owners must still be paid for oil, gas, and NGL extracted from their mineral acreage during the bankruptcy process. In light of this, we do not expect the entry of one of our operators or purchasers into bankruptcy proceedings would materially affect our operating results.
Furthermore, as PhoenixOp increases the extent of its operations and generates revenue from the sale of crude oil and natural gas delivered to purchasers, we expect that our concentration of revenue and accounts receivable among a limited number of third-party E&P operators will decrease, and we will achieve greater control over the terms of the sales agreements entered into among PhoenixOp and the purchasers.
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Table of Contents
Item 4. Controls and Procedures
Limitations on Effectiveness of Controls and Procedures
In designing and evaluating our disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.
Evaluation of Disclosure Controls and Procedures
Our management, with the participation of our principal executive officer and principal financial officer, evaluated, as of the end of the period covered by this Quarterly Report, the effectiveness of our disclosure controls and procedures (as that term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were not effective at the reasonable assurance level as of September 30, 2026 as a result of the material weaknesses described below.
A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of a company’s annual or interim financial statements will not be prevented or detected on a timely basis. In connection with the audit of our consolidated financial statements as of and for the year ended December 31, 2025, our auditors identified several material weaknesses in our internal control over financial reporting. The material weaknesses identified were: (i) inadequate segregation of duties within key financial areas; (ii) entity-level controls that were not sufficiently designed, documented or consistently maintained across the Committee of Sponsoring Organizations of the Treadway Commission (COSO) components to provide reasonable assurance that material misstatements would be prevented or detected on a timely basis; (iii) ineffective processes for identifying and assessing risks impacting internal control over financial reporting; (iv) insufficient evaluation and determination as to whether components of internal controls were present and functioning; (v) ineffective information technology general controls supporting the financial reporting process; and (vi) ineffective controls over the completeness and accuracy of information used in the operation of control activities.
These material weaknesses did not result in any identified material misstatements in the Company’s condensed consolidated financial statements included in this Quarterly Report. However, these material weaknesses could result in a misstatement of the Company’s financial statements that would not be prevented or detected on a timely basis.
Management’s Remediation Efforts
Management has begun implementing measures designed to remediate the material weaknesses described above. These remediation efforts include, but are not limited to: enhancing segregation of duties within financial reporting and related systems; enhancing the design and documentation of entity-level controls across the COSO components; strengthening the Company’s formal risk assessment processes related to financial reporting; implementing additional procedures to evaluate whether internal control components are present and functioning; implementing improvements to information technology general controls, including user access management, system change management, and system monitoring controls; establishing additional controls over the completeness and accuracy of information used in financial reporting processes; and expanding internal control documentation, training and monitoring activities.
These measures include engaging with external consulting firms to assist with technical accounting matters and to improve the design and operating effectiveness of our internal control over financial reporting. In addition, the Company implemented a new accounting system effective January 1, 2026, which management believes will enhance financial reporting processes and support improvements to internal control over financial reporting. The Company will continue to evaluate the effectiveness of controls associated with this system as part of its remediation efforts.
Changes in Internal Control over Financial Reporting
We are taking actions to remediate the material weaknesses relating to our internal control over financial reporting, as described above. Except as discussed above, there were no changes in our internal control over financial reporting (as that term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) during the quarter ended September 30, 2026 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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Table of Contents
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
We have been, are, and/or may in the future be involved in various legal proceedings, lawsuits, regulatory investigations, and other claims in the ordinary course of business. Such matters are subject to many uncertainties, and outcomes are not predictable with certainty. In particular, due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment-related disputes. Based on currently available information and after consultation with legal counsel, in the opinion of our management, none of the matters, disputes, or claims we are involved in, if decided adversely, will have a material adverse effect on our financial condition, cash flows, or results of operations. We have not recorded any material accruals related to these matters as of September 30, 2026. See “Notes to the Condensed Consolidated Financial Statements—Note 13 – Commitments and Contingencies” of the notes to the condensed consolidated financial statements included elsewhere in this Quarterly Report.
Item 1A. Risk Factors
In addition to the other information set forth in this Quarterly Report, you should carefully consider the factors set forth in the section of our 2025 Annual Report entitled “Risk Factors.” These factors could materially adversely affect our business, financial condition, liquidity, results of operations and capital position, and could cause our actual results to differ materially from our historical results or the results contemplated by any forward-looking statements contained in this Quarterly Report. There have been no material changes from the risk factors disclosed under the heading “Risk Factors” in our 2025 Annual Report.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
(a) Recent Sales of Unregistered Securities: None.
(b) Use of Proceeds: On May 14, 2025, the registration statement with respect to up to $750.0 million aggregate principal amount of Registered Notes (File No. 333-282862) was declared effective and the Company commenced the offering of the Registered Notes on a continuous basis. Crescent Securities Group, Inc. currently acts as managing broker-dealer for the offering. The offering of the Registered Notes is ongoing, and, as of the date of this Quarterly Report, the Company has sold $104.3 million aggregate principal amount of Registered Notes, before payment of broker-dealer commissions of approximately $0.6 million and transaction fees and expenses. The proceeds of the Registered Notes have been and will continue to be used as described in the prospectus with respect to the offering.
On July 7, 2026, the registration statement with respect to up to $100.0 million aggregate principal amount of Phoenix Flex Notes (File No. 333-296428) was declared effective, and the Company commenced the offering of the Phoenix Flex Notes on a continuous basis. Crescent Securities Group, Inc. currently acts as managing broker-dealer for the offering. The offering of the Phoenix Flex Notes is ongoing, and, as of the date of this Quarterly Report, the Company has sold $22.5 million aggregate principal amount of Phoenix Flex Notes, before payment of broker-dealer commissions of approximately $0.1 million and transaction fees and expenses. The proceeds of the Phoenix Flex Notes will be used as described in the prospectus with respect to the offering.
(c) Purchases of Equity Securities by the Issuer and Affiliated Purchasers: None.
Item 3. Defaults Upon Senior Securities
None.
Item 4. Mine Safety Disclosures
Not applicable.
Item 5. Other Information
During the three months ended September 30, 2026,
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10-Q Oil and Gas Disclosures
Our Oil and Natural Gas Properties
Productive Wells
Productive wells consist of producing wells, wells capable of production, and exploratory, development, or extension wells that are not dry wells. As of September 30, 2026, we owned mineral, royalty, and working interests in 8,843 productive wells, the majority of which are oil wells that also produce natural gas and NGL.
As of September 30, 2026, we had 241 wells that fall under our “wells in progress” (“WIP”) category, and we had 56.6 net WIP. We define a WIP as a development well in a stage preliminary to production. We utilize both proprietary and public systems to identify WIPs based on four distinct criteria: (i) a well that is not actively being drilled but is in the process of being developed; (ii) a well currently being drilled and awaiting completion; (iii) a drilled well in the completion process; and (iv) a drilled well that has been completed but is not yet producing. This term serves as a guide in our acquisition strategy, enabling us to pinpoint lower-risk investment opportunities for our stakeholders.
Drilling Results
In the nine months ended September 30, 2026, the E&P operators of our properties, including PhoenixOp, drilled 445 gross and 53.6 net productive development wells on the acreage underlying our mineral and royalty interests. This compares to 278 gross and 44.4 net productive development wells drilled by E&P operators on the acreage underlying our mineral and royalty interests in the nine months ended September 30, 2025.
Included in our total drilled wells figures, as of September 30, 2026, PhoenixOp had drilled a total of 152 gross and 131.6 net productive development wells, all of which were drilled in the Williston Basin in North Dakota and Montana. PhoenixOp has also drilled a total of 27 gross and 27 net saltwater disposal wells, and had 81 gross and 49.7 net development wells in progress as of September 30, 2026.
As a holder of mineral and royalty interests, we generally are not provided information as to whether any wells drilled on the properties underlying our acreage are classified as exploratory. We are not aware of any dry holes drilled on the acreage underlying our mineral and royalty interests during the relevant periods.
Wells
As of September 30, 2026, we owned mineral, royalty, and working interests in 8,843 total gross wells and 208.6 total net wells. The following table sets forth information about the productive wells in which we have a mineral or working interest as of September 30, 2026:
|
|
Well Count |
|
|||||||||||||
|
|
Oil |
|
|
Gas |
|
||||||||||
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
||||
Basin or Producing Region |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Bakken/Williston Basin |
|
|
5,308 |
|
|
|
184.9 |
|
|
|
3 |
|
|
|
0.0 |
|
Denver-Julesburg Basin/Rockies/Niobrara/PRB |
|
|
1,727 |
|
|
|
20.8 |
|
|
|
7 |
|
|
|
0.0 |
|
Permian Basin |
|
|
783 |
|
|
|
1.4 |
|
|
|
2 |
|
|
|
0.0 |
|
Other |
|
|
495 |
|
|
|
1.5 |
|
|
|
518 |
|
|
|
0.0 |
|
Total |
|
|
8,313 |
|
|
|
208.6 |
|
|
|
530 |
|
|
|
0.0 |
|
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Table of Contents
Acreage of Mineral and Working Interests
The following tables set forth information relating to the acreage underlying our mineral and working interests as of September 30, 2026:
Acreage of Mineral Interest
|
|
Net Royalty Acres |
|
|||||||||
|
|
Developed |
|
|
Undeveloped |
|
|
Total |
|
|||
Basin |
|
|
|
|
|
|
|
|
|
|||
Bakken/Williston Basin |
|
|
60,836 |
|
|
|
112,994 |
|
|
|
173,830 |
|
Denver-Julesburg Basin/Rockies/Niobrara/PRB |
|
|
12,712 |
|
|
|
15,805 |
|
|
|
28,517 |
|
Permian Basin |
|
|
929 |
|
|
|
83 |
|
|
|
1,012 |
|
Other |
|
|
12,302 |
|
|
|
361,576 |
|
|
|
373,878 |
|
Total Net Royalty Acres |
|
|
86,779 |
|
|
|
490,458 |
|
|
|
577,237 |
|
|
|
Gross Royalty Acres |
|
|||||||||
|
|
Developed |
|
|
Undeveloped |
|
|
Total |
|
|||
Basin |
|
|
|
|
|
|
|
|
|
|||
Bakken/Williston Basin |
|
|
381,565 |
|
|
|
293,610 |
|
|
|
675,175 |
|
Denver-Julesburg Basin/Rockies/Niobrara/PRB |
|
|
106,075 |
|
|
|
81,896 |
|
|
|
187,971 |
|
Permian Basin |
|
|
17,472 |
|
|
|
8,810 |
|
|
|
26,282 |
|
Other |
|
|
28,401 |
|
|
|
1,000,597 |
|
|
|
1,028,998 |
|
Total Gross Royalty Acres |
|
|
533,513 |
|
|
|
1,384,913 |
|
|
|
1,918,426 |
|
Acreage of Working Interest
|
|
Net Mineral Acres |
|
|||||||||
|
|
Developed |
|
|
Undeveloped |
|
|
Total |
|
|||
Basin |
|
|
|
|
|
|
|
|
|
|||
Bakken/Williston Basin |
|
|
88,620 |
|
|
|
366,250 |
|
|
|
454,870 |
|
Denver-Julesburg Basin/Rockies/Niobrara/PRB |
|
|
6,240 |
|
|
|
40,581 |
|
|
|
46,821 |
|
Permian Basin |
|
|
59 |
|
|
|
0 |
|
|
|
59 |
|
Other |
|
|
643 |
|
|
|
220,874 |
|
|
|
221,517 |
|
Total Net Mineral Acres |
|
|
95,562 |
|
|
|
627,705 |
|
|
|
723,267 |
|
|
|
Gross Mineral Acres |
|
|||||||||
|
|
Developed |
|
|
Undeveloped |
|
|
Total |
|
|||
Basin |
|
|
|
|
|
|
|
|
|
|||
Bakken/Williston Basin |
|
|
177,474 |
|
|
|
617,284 |
|
|
|
794,758 |
|
Denver-Julesburg Basin/Rockies/Niobrara/PRB |
|
|
28,137 |
|
|
|
119,546 |
|
|
|
147,683 |
|
Permian Basin |
|
|
1,654 |
|
|
|
1 |
|
|
|
1,655 |
|
Other |
|
|
5,829 |
|
|
|
940,487 |
|
|
|
946,316 |
|
Total Gross Mineral Acres |
|
|
213,094 |
|
|
|
1,677,318 |
|
|
|
1,890,412 |
|
Acreage Expirations
As of September 30, 2026, we have 101,964 gross and 51,299 net working interest acres expiring through the end of 2027, with an additional 122,252 gross and 59,655 net working interest acres expiring in 2028, and 168,916 gross and 85,665 net working interest acres expiring in 2029. The remaining 285,725 gross and 142,212 net working interest acres expire in years 2030 and beyond.
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Table of Contents
Oil, Natural Gas, and NGL Reserves
The following table presents our estimated proved and probable oil, natural gas, and NGL reserves as of each of the dates indicated:
|
|
As of |
|
|
As of December 31, |
|
||||||||||
|
|
September 30, 2026(1)(2) |
|
|
2025(2)(3) |
|
|
2024(2)(4) |
|
|
2023(2)(5) |
|
||||
Estimated proved developed reserves |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Oil (Bbl) |
|
|
52,267,658 |
|
|
|
39,367,935 |
|
|
|
18,624,758 |
|
|
|
7,124,194 |
|
Natural gas (Mcf) |
|
|
47,401,727 |
|
|
|
32,222,398 |
|
|
|
20,819,874 |
|
|
|
12,250,285 |
|
Natural gas liquids (Bbl) |
|
|
10,318,029 |
|
|
|
6,882,740 |
|
|
|
2,848,355 |
|
|
|
1,514,761 |
|
Total (Boe)(6:1)(6) |
|
|
70,485,974 |
|
|
|
51,621,074 |
|
|
|
24,943,092 |
|
|
|
10,680,669 |
|
Estimated proved undeveloped reserves |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Oil (Bbl) |
|
|
77,616,730 |
|
|
|
49,888,499 |
|
|
|
31,197,795 |
|
|
|
24,925,841 |
|
Natural gas (Mcf) |
|
|
64,699,153 |
|
|
|
27,916,131 |
|
|
|
17,491,089 |
|
|
|
19,565,808 |
|
Natural gas liquids (Bbl) |
|
|
17,674,451 |
|
|
|
7,451,608 |
|
|
|
4,753,257 |
|
|
|
6,648,747 |
|
Total (Boe)(6:1)(6) |
|
|
106,074,373 |
|
|
|
61,992,797 |
|
|
|
38,866,234 |
|
|
|
34,835,556 |
|
Estimated proved reserves |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Oil (Bbl) |
|
|
129,884,387 |
|
|
|
89,256,434 |
|
|
|
49,822,553 |
|
|
|
32,050,035 |
|
Natural gas (Mcf) |
|
|
112,100,880 |
|
|
|
60,138,529 |
|
|
|
38,310,963 |
|
|
|
31,816,093 |
|
Natural gas liquids (Bbl) |
|
|
27,992,480 |
|
|
|
14,334,348 |
|
|
|
7,601,612 |
|
|
|
8,163,508 |
|
Total (Boe)(6:1)(6) |
|
|
176,560,347 |
|
|
|
113,613,871 |
|
|
|
63,809,326 |
|
|
|
45,516,226 |
|
Percent proved developed |
|
|
40 |
% |
|
|
45 |
% |
|
|
39 |
% |
|
|
23 |
% |
Estimated probable undeveloped reserves |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Oil (Bbl) |
|
|
232,952,916 |
|
|
|
178,532,093 |
|
|
|
107,769,309 |
|
|
|
74,877,268 |
|
Natural gas (Mcf) |
|
|
138,104,464 |
|
|
|
105,888,056 |
|
|
|
134,083,603 |
|
|
|
88,184,111 |
|
Natural gas liquids (Bbl) |
|
|
44,394,486 |
|
|
|
31,779,646 |
|
|
|
— |
|
|
|
— |
|
Total (Boe)(6:1)(6) |
|
|
300,364,813 |
|
|
|
227,959,749 |
|
|
|
130,116,576 |
|
|
|
89,574,620 |
|
55
Table of Contents
At September 30, 2026, total estimated proved reserves were approximately 176,560,347 Boe, a 62,946,476 Boe net increase from the estimate of 113,613,871 Boe at December 31, 2025. Proved developed reserves of 70,485,974 Boe represented an increase of approximately 18,864,900 Boe from the estimate of 51,621,074 Boe at December 31, 2025 as a result of transfers of 22,821,348 Boe from proved undeveloped reserves, extensions and acquisitions of new properties of 4,974,800 Boe, and net negative revisions of previous estimates of (8,931,248) Boe, which comprised: (i) negative revisions due to effective-date roll-forward of reserve estimates of (8,775,582) Boe, (ii) positive price revisions of 181,753 Boe, (iii) negative revisions of (106,917) Boe due to divestitures and trades, (iv) positive revisions of 25,247 Boe due to schedule adjustments, (v) positive shrink and yield revisions of 4,075,017 Boe, (vi) positive interest adjustments of 2,157,836 Boe, (vii) positive revisions of 1,923,375 Boe due to changes in lifting cost, (viii) negative well performance revisions of (8,418,992) Boe, and (ix) positive other revisions of 7,015 Boe. Proved undeveloped reserves of 106,074,373 Boe represented an increase of approximately 44,081,576 Boe from the estimate of 61,992,797 Boe at December 31, 2025 as a result of extensions and acquisitions of new properties of 70,381,209 Boe, transfers of (22,821,348) Boe to proved developed reserves, and net negative revisions of previous estimates of (3,478,285) Boe, which comprised: (i) negative revisions due to effective-date roll-forward of reserve estimates of (2,520,924) Boe, (ii) positive price revisions of 219,061 Boe, (iii) negative revisions of (11,747,268) Boe due to divestitures and trades, (iv) negative revisions of (298,939) Boe due to schedule adjustments, (v) positive shrink and yield revisions of 1,139,909 Boe, (vi) positive interest adjustments of 8,384,141 Boe, (vii) positive revisions of 866,632 Boe due to changes in lifting cost, (viii) positive well performance revisions of 478,627 Boe, and (ix) positive other revisions of 476 Boe. During the nine months ended September 30, 2026, approximately $834.7 million in capital expenditures went toward the acquisition and development of proved reserves, which includes drilling, completion, facility, and capital workover costs, and the proved portion of property acquisitions.
At December 31, 2025, total estimated proved reserves were approximately 113,613,871 Boe, a 49,804,545 Boe net increase from the estimate of 63,809,326 Boe at December 31, 2024. The increase was primarily the result of extensions and discoveries of 71,088,631 Boe, partially offset by revisions of previous estimates of (12,396,675) Boe and production of (9,924,337) Boe during the year. Proved developed reserves of 51,621,074 Boe represented an increase of 26,677,982 Boe from December 31, 2024, primarily due to extensions and discoveries of 8,782,530 Boe, transfers of 19,515,344 Boe from proved undeveloped reserves, purchases of reserves in place of 571,500 Boe, and revisions of previous estimates of 8,008,132 Boe, partially offset by production of (9,924,337) Boe and divestitures and trades of (275,187) Boe. The revisions of previous estimates affecting proved developed reserves comprised of timing adjustments associated with the effective-date roll-forward, write-downs of certain locations, shrink and yield revisions, well performance revisions, price revisions, interest adjustments, and changes in lifting costs. Proved undeveloped reserves of 61,992,797 Boe represented an increase of 23,126,563 Boe from December 31, 2024, primarily due to extensions and discoveries of 62,306,101 Boe and purchases of reserves in place of 740,613 Boe, partially offset by transfers of (19,515,344) Boe to proved developed reserves and revisions of previous estimates of (20,404,807) Boe. The revisions of previous estimates affecting proved undeveloped reserves primarily reflected timing adjustments associated with the effective-date roll-forward of reserve estimates, write-downs of certain locations, shrink and yield revisions, well performance revisions, price revisions, interest adjustments, and changes in lifting costs. During the year ended December 31, 2025, approximately $686.8 million in capital expenditures went toward the development of proved reserves, which includes drilling, completion, and other facility costs associated with acquiring and developing wells.
At December 31, 2024, total estimated proved reserves were approximately 63,809,326 Boe, an 18,293,100 Boe net increase from the previous year end’s estimate of 45,516,226 Boe. Proved developed reserves of 24,943,092 Boe increased approximately 14,262,423 Boe from December 31, 2023 as a result of proved developed reserves acquisitions of 1,047,809 Boe, extensions of 3,268,997 Boe, and total positive revisions of previous estimates of 14,759,886 Boe, partially offset by divestitures of 71,887 Boe and production from proved developed reserves of 4,742,381 Boe. The total positive revisions of previous estimates comprised: (i) positive price revisions of 1,263 Boe; (ii) positive transfer of 14,871,911 Boe from proved undeveloped to proved developed reserves; (iii) negative well performance revisions of (481,161) Boe; (iv) positive revisions of 715,795 Boe due to interest changes; and (v) negative revisions of (347,922) Boe due to changes in lifting cost. Proved undeveloped reserves of 38,866,234 Boe increased approximately 4,030,678 Boe from December 31, 2023 as a result of proved undeveloped reserves extensions of 21,207,289 Boe and total negative revisions of previous estimates of 17,176,612 Boe. The total negative revisions of previous estimates comprised: (i) positive price revisions of 48,935 Boe; (ii) negative transfer of (14,871,911) Boe from proved undeveloped to proved developed reserves; and (iii) negative well performance revisions of (2,353,636) Boe due to asset development reconfiguration and type curve adjustments. During the year ended December 31, 2024, approximately $87.4 million in capital expenditures were related to the conversion of proved undeveloped reserves to
56
Table of Contents
proved developed reserves. During the year ended December 31, 2024, approximately $450.0 million in capital expenditures went toward the acquisition and development of proved developed reserves, which includes drilling, completion, and other facility costs associated with acquiring and developing wells. All proved undeveloped reserves disclosed as of December 31, 2024 are scheduled to be converted to proved developed status within five years of initial disclosure.
At December 31, 2023, total estimated proved reserves were approximately 45,516,226 Boe, a 40,553,802 Boe net increase from the previous year end’s estimate of 4,962,424 Boe. Proved developed reserves of 10,680,669 Boe increased approximately 5,718,245 Boe from December 31, 2022 as a result of proved developed reserves acquisitions of 1,426,545 Boe, extensions of 5,682,894 Boe, and total positive revisions of previous estimates of 616,010 Boe, partially offset by production from proved developed reserves of 2,007,205 Boe. The total positive revisions of previous estimates comprised: (i) negative price revisions of (13,622) Boe; (ii) transfer of (89,378) Boe from proved developed to proved undeveloped due to previous misclassifications of reserves; (iii) positive well performance revisions of 515,938 Boe; and (iv) positive revisions of 203,072 Boe due to changes in lifting cost. Proved undeveloped reserves of 34,835,556 Boe increased approximately 34,835,556 Boe from December 31, 2022 as a result of revisions due to previous misclassification of 89,378 Boe of reserves as proved developed reserves and due to the addition of 34,746,179 Boe of operated proved undeveloped reserves stemming from the signing of a drilling rig contract in June 2023. During the year ended December 31, 2023, approximately $171.2 million in capital expenditures went toward the acquisition and development of proved developed reserves, which includes drilling, completion, and other facility costs associated with acquiring and developing wells. At December 31, 2022, there were no proved undeveloped reserves. Therefore, no capital expenditures for the year ended December 31, 2023 were related to the conversion of proved undeveloped reserves to proved developed reserves. All proved undeveloped reserves disclosed as of December 31, 2023 are scheduled to be converted to proved developed status within five years of initial disclosure.
Delivery Commitments
Crude Oil Commitments
We are subject to arrangements pursuant to which we have committed to deliver barrels of crude oil to a purchaser through December 31, 2030. We will be subject to a shortfall fee for failure to meet this commitment. As a part of these arrangements, we have dedicated to the counterparties certain rights to all oil extracted from our wells in certain properties in Dunn County, North Dakota. We have assessed the productivity potential of our leasehold in the area, as well as the feasibility of executing an operational plan to extract oil on our leasehold within the commitment period and dedication area, and deemed it to be reasonable to enter into such an agreement. As of September 30, 2026, we delivered approximately 1.5 million barrels of crude oil and the remaining aggregate commitment under the contract is approximately 0.7 million barrels of crude oil. Based on current production levels from the dedicated acreage, we believe we have sufficient production capacity to satisfy the remaining contractual volume commitments. However, future production levels are subject to operational, commodity price, and reservoir performance risks. In the event of a shortfall, any associated fees would not be expected to materially impair our liquidity position.
Natural Gas Gathering Commitments
In May 2026, we entered into a fifteen-year gas gathering and processing contract with a third-party provider pursuant to which we have committed to deliver substantially all natural gas production from certain dedicated acreage in the Divide, Williams, and Dunn Counties in North Dakota, for gathering and processing services. We are subject to a five-year minimum volume commitment of 20.0 million Mcf beginning in March 2027, with an annual minimum requirement of 4.0 million Mcf, and may be subject to a shortfall fee. Deliveries in excess of annual commitments generate volume credits that may be applied against future annual commitments. As of September 30, 2026, we delivered approximately 0.2 million Mcf, which will be credited toward the first year’s minimum volume requirement. Under this agreement, we pay gathering, compression, and other service fees based primarily on production volumes delivered. We have also agreed to fund certain AIC costs associated with the construction of gathering infrastructure totaling $10.0 million, of which $4.0 million was paid in May 2026 and $3.0 million is to be paid in November 2026. The final installment of $3.0 million is payable upon the achievement of certain specified milestones by the provider.
57
Table of Contents
Select Production and Operating Statistics
The following table presents information regarding our production of oil, natural gas, and NGL and certain price and cost information for each of the periods indicated:
|
|
For the Nine Months Ended September 30, |
|
|
For the Years Ended December 31, |
|
||||||||||||||
|
|
2026 |
|
|
2025 |
|
|
2025 |
|
|
2024 |
|
|
2023 |
|
|||||
Production Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Bakken |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Oil (Bbl) |
|
|
9,093,408 |
|
|
|
5,179,839 |
|
|
|
7,831,787 |
|
|
|
3,022,810 |
|
|
|
943,930 |
|
Natural gas (Mcf)(1) |
|
|
3,306,878 |
|
|
|
1,270,611 |
|
|
|
2,176,128 |
|
|
|
1,301,782 |
|
|
|
1,123,859 |
|
Natural gas liquids (Bbl) |
|
|
753,413 |
|
|
|
290,212 |
|
|
|
576,561 |
|
|
|
270,219 |
|
|
|
88,762 |
|
Total (Boe)(6:1)(2) |
|
|
10,397,967 |
|
|
|
5,681,820 |
|
|
|
8,771,036 |
|
|
|
3,509,992 |
|
|
|
1,220,003 |
|
Average daily production (Boe/d)(6:1) |
|
|
38,088 |
|
|
|
20,813 |
|
|
|
24,030 |
|
|
|
9,590 |
|
|
|
3,342 |
|
All Properties |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Oil (Bbl) |
|
|
9,687,251 |
|
|
|
5,731,412 |
|
|
|
8,641,089 |
|
|
|
3,830,461 |
|
|
|
1,446,928 |
|
Natural gas (Mcf)(1) |
|
|
4,263,360 |
|
|
|
2,146,843 |
|
|
|
3,427,154 |
|
|
|
2,979,341 |
|
|
|
2,152,939 |
|
Natural gas liquids (Bbl) |
|
|
850,878 |
|
|
|
388,083 |
|
|
|
712,056 |
|
|
|
415,363 |
|
|
|
201,454 |
|
Total (Boe)(6:1)(2) |
|
|
11,248,689 |
|
|
|
6,477,302 |
|
|
|
9,924,337 |
|
|
|
4,742,381 |
|
|
|
2,007,205 |
|
Average daily production (Boe/d)(6:1) |
|
|
41,204 |
|
|
|
23,726 |
|
|
|
27,190 |
|
|
|
12,993 |
|
|
|
5,499 |
|
Average Realized Prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Bakken |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Oil (Bbl) |
|
$ |
84.16 |
|
|
$ |
67.09 |
|
|
$ |
64.02 |
|
|
$ |
71.77 |
|
|
$ |
71.43 |
|
Natural gas (Mcf) |
|
$ |
2.49 |
|
|
$ |
2.64 |
|
|
$ |
2.33 |
|
|
$ |
2.12 |
|
|
$ |
3.47 |
|
Natural gas liquids (Bbl) |
|
$ |
25.09 |
|
|
$ |
21.03 |
|
|
$ |
20.76 |
|
|
$ |
23.53 |
|
|
$ |
26.70 |
|
All Properties |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Oil (Bbl) |
|
$ |
82.78 |
|
|
$ |
65.36 |
|
|
$ |
62.45 |
|
|
$ |
68.49 |
|
|
$ |
73.10 |
|
Natural gas (Mcf) |
|
$ |
2.39 |
|
|
$ |
2.57 |
|
|
$ |
2.31 |
|
|
$ |
1.86 |
|
|
$ |
3.15 |
|
Natural gas liquids (Bbl) |
|
$ |
25.22 |
|
|
$ |
21.51 |
|
|
$ |
20.90 |
|
|
$ |
25.22 |
|
|
$ |
27.50 |
|
Average Unit Cost per Boe (6:1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
All Properties |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Operating costs, production and ad valorem taxes |
|
$ |
23.53 |
|
|
$ |
19.74 |
|
|
$ |
18.99 |
|
|
$ |
16.11 |
|
|
$ |
16.18 |
|
Operating costs excluding taxes |
|
$ |
16.68 |
|
|
$ |
14.75 |
|
|
$ |
14.38 |
|
|
$ |
10.75 |
|
|
$ |
10.86 |
|
Percentage of revenue(3) |
|
|
31.7 |
% |
|
|
34.9 |
% |
|
|
33.5 |
% |
|
|
26.4 |
% |
|
|
16.7 |
% |
Depletion of Oil and Natural Gas Properties
We account for our oil and gas properties under the successful efforts method of accounting. Under this method, the costs of development wells are capitalized to proved properties whether those wells are successful or unsuccessful. Capitalized drilling and completion costs, including lease and well equipment, intangible development costs, and operational support facilities, are depleted using the units-of-production method based on estimated proved developed reserves. Proved leasehold costs are also depleted; however, the units-of-production method is based on estimated total proved reserves. The computation of depletion expense takes into consideration restoration, dismantlement, and abandonment costs, as well as the anticipated proceeds from salvaging equipment.
Depletion expense was $222.1 million and $113.3 million for the nine months ended September 30, 2026 and 2025, respectively. On a per unit basis, depletion expense was $19.74 per Boe and $17.49 per Boe for the nine months ended September 30, 2026 and 2025, respectively. The increase in depletion expense was primarily due to higher production volumes and a higher depletion rate, which resulted from growth in the depletable cost base outpacing growth in proved reserves. Under the successful efforts method, development costs are depleted over proved developed reserves, while leasehold costs are
58
Table of Contents
depleted over total proved reserves, resulting in a higher depletion rate for development costs. We expect depletion expense to continue to increase in subsequent periods as our net production of oil, natural gas, and NGL increases.
PV-10
|
|
As of September 30, |
|
|
As of December 31, |
|
||||||||||||||
(in thousands) |
|
2026 |
|
|
2025 |
|
|
2025 |
|
|
2024 |
|
|
2023 |
|
|||||
PV-10 (estimated proved developed reserves) |
|
$ |
1,650,791 |
|
|
$ |
901,803 |
|
|
$ |
1,094,359 |
|
|
$ |
644,098 |
|
|
$ |
289,809 |
|
PV-10 (estimated proved undeveloped reserves) |
|
$ |
1,304,459 |
|
|
$ |
614,591 |
|
|
$ |
687,042 |
|
|
$ |
424,595 |
|
|
$ |
257,472 |
|
PV-10 (estimated total proved reserves) |
|
$ |
2,955,250 |
|
|
$ |
1,516,394 |
|
|
$ |
1,781,401 |
|
|
$ |
1,068,693 |
|
|
$ |
547,281 |
|
We calculate PV-10 as the discounted future net cash flows attributable to our proved oil and natural gas reserves before income taxes, discounted at 10% annually. PV-10 differs from the standardized measure of discounted future net cash flows, which is the most directly comparable U.S. GAAP financial measure, because it is calculated on a pre-tax basis. We use PV-10 when assessing the potential return on investment related to our oil and natural gas properties. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future income taxes, and is useful for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize PV-10 as a basis for comparison of the relative size and value of our reserves to other companies without regard to the specific tax characteristics of such entities.
Because the Company is a limited liability company and has currently elected to be treated as a partnership for income tax purposes, the pro-rata share of taxable income or loss is included in the individual income tax returns of members based on their percentage of ownership. Consequently, no provision for income taxes is made in our standardized measure of discounted future net cash flows, and so currently our PV-10 is identical to the standardized measure of discounted future net cash flows. Notwithstanding the foregoing, we believe that the presentation of PV-10 is useful to investors because it is a commonly utilized measure in our industry for assessing the value of reserves.
PV-10 is not a substitute for the standardized measure of discounted future net cash flows. Neither PV-10 nor the standardized measure of discounted future net cash flows purports to represent the fair value of our oil and natural gas reserves.
The following table includes a reconciliation of PV-10 to the standardized measure of discounted future net cash flows, the most directly comparable financial measure calculated and presented in accordance with GAAP, for the periods presented:
|
|
As of September 30, |
|
|
As of December 31, |
|
||||||||||||||
(in thousands) |
|
2026 |
|
|
2025 |
|
|
2025 |
|
|
2024 |
|
|
2023 |
|
|||||
Estimated proved developed reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Standardized measure of discounted future net cash flows |
|
$ |
1,650,791 |
|
|
$ |
901,803 |
|
|
$ |
1,094,359 |
|
|
$ |
644,098 |
|
|
$ |
289,809 |
|
Discounted future income taxes |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
PV-10 |
|
$ |
1,650,791 |
|
|
$ |
901,803 |
|
|
$ |
1,094,359 |
|
|
$ |
644,098 |
|
|
$ |
289,809 |
|
Estimated proved undeveloped reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Standardized measure of discounted future net cash flows |
|
$ |
1,304,459 |
|
|
$ |
614,591 |
|
|
$ |
687,042 |
|
|
$ |
424,595 |
|
|
$ |
257,472 |
|
Discounted future income taxes |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
PV-10 |
|
$ |
1,304,459 |
|
|
$ |
614,591 |
|
|
$ |
687,042 |
|
|
$ |
424,595 |
|
|
$ |
257,472 |
|
Estimated total proved reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Standardized measure of discounted future net cash flows |
|
$ |
2,955,250 |
|
|
$ |
1,516,394 |
|
|
$ |
1,781,401 |
|
|
$ |
1,068,693 |
|
|
$ |
547,281 |
|
Discounted future income taxes |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
PV-10 |
|
$ |
2,955,250 |
|
|
$ |
1,516,394 |
|
|
$ |
1,781,401 |
|
|
$ |
1,068,693 |
|
|
$ |
547,281 |
|
59
Table of Contents
Item 6. Exhibits
|
|
|
|
Incorporated by Reference |
|
|
||||
Exhibit No. |
|
Description |
|
Form |
|
Date of First |
|
Exhibit |
|
Filed |
|
|
|
|
|
|
|
|
|
|
|
3.1 |
|
Certificate of Formation of Phoenix Energy One, LLC (f/k/a Phoenix Capital Group Holdings, LLC), dated as of April 16, 2019. |
|
S-1 |
|
10/29/2024 |
|
3.1 |
|
|
3.2 |
|
Certificate of Amendment to the Certificate of Formation of Phoenix Energy One, LLC, dated as of January 23, 2025. |
|
S-1/A |
|
03/28/2025 |
|
3.2 |
|
|
3.3 |
|
Third Amended and Restated Limited Liability Company Agreement of Phoenix Energy One, LLC. |
|
8-K |
|
09/30/2025 |
|
3.1 |
|
|
3.4 |
|
Phoenix Energy One, LLC Share Designation with Respect to the Series A Cumulative Redeemable Preferred Shares. |
|
8-K |
|
09/30/2025 |
|
3.2 |
|
|
4.1 |
|
Indenture, by and between Phoenix Energy One, LLC, as issuer, and Odyssey Transfer and Trust Company, as trustee and collateral agent, dated as of July 7, 2026 (including the Forms of Cash Interest Note and Compound Interest Note). |
|
8-K |
|
07/08/2026 |
|
4.1 |
|
|
10.1 |
|
Junior Lien Intercreditor Agreement, by and among Fortress Credit Corp., Odyssey Transfer and Trust Company, Phoenix Energy One, LLC, Phoenix Operating LLC, the other obligors under the Fortress Credit Agreement, and the other parties from time to time party thereto, dated as of July 7, 2026. |
|
8-K |
|
07/08/2026 |
|
10.1 |
|
|
10.2 |
|
Amendment No. 10 to Amended and Restated Senior Secured Credit Agreement, by and among Phoenix Energy One, LLC, Phoenix Operating LLC, the Guarantors party thereto, the Specified Additional Guarantor, each of the lenders from time to time party thereto, and Fortress Credit Corp., as administrative agent and as collateral agent, dated as of August 12, 2026. |
|
8-K |
|
08/17/2026 |
|
10.1 |
|
|
10.3++ |
|
Limited Waiver and Amendment No. 11 to Amended and Restated Senior Secured Credit Agreement, by and among Phoenix Energy One, LLC, Phoenix Operating LLC, the Guarantors party thereto, the Specified Additional Guarantor, each of the lenders from time to time party thereto, and Fortress Credit Corp., as administrative agent, as collateral agent and as technical agent, dated as of October 21, 2026. |
|
8-K |
|
10/22/2026 |
|
10.1 |
|
|
10.4++ |
|
Form of Wellbore Participation and Assignment Agreement by and among Phoenix Energy One, LLC, Phoenix Operating LLC, and the purchaser party thereto. † |
|
8-K |
|
10/22/2026 |
|
10.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
31.1 |
|
Certifications of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
|
|
|
|
|
|
|
* |
31.2 |
|
Certifications of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
|
|
|
|
|
|
|
* |
32.1 |
|
Certifications of Chief Executive Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
|
|
|
|
|
|
|
** |
32.2 |
|
Certifications of Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
|
|
|
|
|
|
|
** |
|
|
|
|
|
|
|
|
|
|
|
101.INS |
|
Inline XBRL Instance Document – the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. |
|
|
|
|
|
|
|
* |
101.SCH |
|
Inline XBRL Taxonomy Extension Schema with Embedded Linkbase Documents. |
|
|
|
|
|
|
|
* |
|
|
|
|
|
|
|
|
|
|
|
104 |
|
The cover page for the Company’s Quarterly Report on Form 10-Q has been formatted in Inline XBRL and contained in Exhibit 101. |
|
|
|
|
|
|
|
* |
60
Table of Contents
* Filed herewith.
** Furnished herewith.
++ Certain annexes, schedules, and exhibits to this Exhibit have been omitted pursuant to Item 601(a)(5) of Regulation S-K. The Company hereby agrees to furnish supplementally a copy of any omitted annex, schedule, or exhibit to the SEC upon request.
† Management contract or compensatory plan or arrangement.
61
Table of Contents
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.
|
|
PHOENIX ENERGY ONE, LLC |
|
|
|
|
|
Date: November 10, 2026 |
|
By: |
/s/ Adam Ferrari |
|
|
|
Adam Ferrari |
|
|
|
Chief Executive Officer and Director |
|
|
|
(Principal Executive Officer) |
|
|
|
|
Date: November 10, 2026 |
|
By: |
/s/ Curtis Allen |
|
|
|
Curtis Allen |
|
|
|
Chief Financial Officer |
|
|
|
(Principal Financial Officer and Principal Accounting Officer) |
62