Riley Exploration Permian Inc.
03/04/2026 | Press release | Distributed by Public on 03/04/2026 16:05
Annual Report for Fiscal Year Ending December 31, 2025 (Form 10-K)
Management's Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of the Company's financial condition and results of operations should be read in conjunction with the Company's consolidated financial statements and related notes thereto presented in this Annual Report. The following discussion contains "forward-looking statements" that reflect the Company's future plans, estimates, beliefs and expected performance. The Company's actual results could differ materially from those discussed in these forward-looking statements. See "Cautionary Statement Regarding Forward-Looking Statements" and "Part I. Item 1A. Risk Factors."
The following discussion and analysis focuses primarily on our results for 2025 and 2024 and comparisons between those periods. Discussion of 2023 results and comparisons between 2024 and 2023 are not included herein and can be found in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II, Item 7 of our 2024 Annual Report on Form 10-K.
Overview
Riley Permian is a growth-oriented, independent oil and natural gas company focused on horizontal drilling of conventional oil-saturated and liquids-rich formations in the Permian Basin that produce long-term cash flows. The majority of our acreage is located in Yoakum County, Texas and Eddy County, New Mexico.
Our strategic business objectives include enhancing the rate of return on our invested capital, generating sustainable free cash flow, maintaining a strong and flexible balance sheet and maximizing our returns to shareholders. We implement this strategy primarily through identification and capture of attractive development opportunities, optimization of our assets and pursuing complementary growth opportunities that increase our scale and meet our strategic and financial objectives.
Recent Developments
Geopolitical and Economic Conditions
Commodity prices remain volatile. General domestic and international economic, market and political conditions, including military conflicts, global economic growth, unpredictability of tariffs, actions of OPEC+ countries and changes to the current political environment could prolong market volatility and cause a decline in commodity prices.
Although the broader rate of inflation has moderated, we continue to monitor the risk of persistent cost pressures in specific areas of our operating expenses and capital expenditures. Our margins may be compressed if costs increase more than commodity prices. Additionally, the current interest rate environment remains sensitive to shifts in macroeconomic factors and central bank policies. Increased interest rates could have the effects of raising our cost of capital and the potential for depressing economic growth, either of which (or the combination thereof) could hurt the financial and operating results of our business.
The Company cannot estimate the length or gravity of the future impact these conditions will have on the Company's results of operations, financial position, liquidity and the value of the oil and natural gas reserves.
Midstream Sale
On December 3, 2025, the Company sold all of our membership interests in Dovetail Midstream, LLC, a wholly owned subsidiary of the Company that holds certain midstream infrastructure projects in Eddy County, New Mexico, to Targa for an aggregate cash purchase price of approximately $111 million, subject to customary purchase price adjustments. The Midstream Sale also provided for the subsequent sale by the Company of certain compressor station assets for an aggregate cash purchase price of approximately $10 million plus reimbursement of $1.4 million of capital improvements; this second transaction closed on December 24, 2025. In connection with the Midstream Sale, the Company recognized a pre-tax gain of $71.7 million, net of $2.6 million of transaction costs, which was recorded in our consolidated statement of operations. The Company also has the right to earn up to an additional $60 million in cash payments contingent upon achieving certain volumetric performance thresholds over a five-year period.
Viking Sale
On November 21, 2025, the Company sold its interest in oil and natural gas properties in Texas outside of the Company's acreage in the Champions field, which had a net carrying value of $10.4 million to an affiliate of Combo. The properties consisted of six established units in Lee and Fayette Counties, Texas, which were jointly developed by the Company and Combo. In exchange for the Company's interest in these assets, we received and subsequently retired 250,000 shares of the Company's common stock. The net carrying value of the assets plus cash paid of $0.8 million less the tax impact of the sale resulted in a reduction to additional paid-in capital of $10.2 million.
Silverback Acquisition
On July 1, 2025, the Company closed on the acquisition of 100% of the ownership interests of Silverback for approximately $123 million, which included approximately $120 million paid in cash and approximately $3 million of estimated fair value related to potential earnout payments. The Silverback Acquisition added approximately 40,000 net acres directly adjacent to and overlapping with the Company's existing core acreage primarily in Eddy County, New Mexico. The Company funded the acquisition with cash on hand and borrowings under our Credit Facility.
RPC Power Joint Venture
During the year ended December 31, 2025, the Company contributed an additional $15.8 million to RPC Power which increased our total capital contributions to $39.5 million. As of December 31, 2025, the Company owned 50% of the joint venture. On December 31, 2025, RPC Power declared a $3 million dividend of which $1.5 million was the Company's portion. The dividend was paid in January 2026.
Credit Facility Amendment
On December 13, 2024, the Company entered into the sixteenth amendment to the Credit Facility to, among other things, extend the stated maturity date from April 2026 to December 2028 (or if any Senior Notes are then outstanding, the date that is 181 days prior to the earliest stated maturity date of such Senior Notes, in this case October 2027), increase the borrowing base from $375 million to $400 million, and add one new lender to the lending group. In December 2025, through the semi-annual redetermination process, the Company's borrowing base was reaffirmed at $400 million and the requirement for natural gas hedging was removed.
Results of Operations
Comparison for the years ended December 31, 2025, and 2024.
|
Year Ended December 31,
|
||||||||||||||
| 2025 | 2024 | |||||||||||||
|
Revenues (in thousands):(1)
|
||||||||||||||
|
Oil sales, net
|
$ | 398,341 | $ | 408,935 | ||||||||||
|
Natural gas sales, net
|
(3,322) | (1,412) | ||||||||||||
|
NGLs sales, net
|
(3,039) | 2,278 | ||||||||||||
| Oil and natural gas sales, net | $ | 391,980 | $ | 409,801 | ||||||||||
| Production Data, net: | ||||||||||||||
| Oil (MBbls) | 6,328 | 5,519 | ||||||||||||
| Natural gas (MMcf) | 11,669 | 7,484 | ||||||||||||
| NGLs (MBbls) | 2,387 | 1,486 | ||||||||||||
| Total (MBoe) | 10,660 | 8,252 | ||||||||||||
| Daily combined volumes (Boe/d) | 29,205 | 22,546 | ||||||||||||
| Daily oil volumes (Bbls/d) | 17,337 | 15,079 | ||||||||||||
|
Average Realized Prices:(1)
|
||||||||||||||
| Oil ($ per Bbl) | $ | 62.95 | $ | 74.10 | ||||||||||
| Natural gas ($ per Mcf) | $ | (0.28) | $ | (0.19) | ||||||||||
|
NGLs ($ per Bbl)
|
$ | (1.27) | $ | 1.53 | ||||||||||
|
Average Realized Prices, including derivative settlements:(1)(2)
|
||||||||||||||
| Oil ($ per Bbl) | $ | 65.46 | $ | 73.67 | ||||||||||
| Natural gas ($ per Mcf) | $ | (0.22) | $ | 0.37 | ||||||||||
|
NGLs ($ per Bbl)(3)
|
$ | (1.27) | $ | 1.53 | ||||||||||
_____________________
(1)The Company's oil, natural gas and NGL sales are presented net of GP&T costs. These costs, related to natural gas and NGLs, at times exceeded the price we received and resulted in negative average realized prices.
(2)The Company's calculation of the effects of derivative settlements includes gains and losses on the settlement of our commodity derivative contracts. These gains and losses are included under other income (expense) in the Company's consolidated statements of operations.
(3)During the periods presented, the Company did not have any NGL derivative contracts in place.
Oil and Natural Gas Revenues
Our revenues are derived from the sale of our oil and natural gas production, including the sale of NGLs that are extracted from our natural gas during processing. Realized prices and revenues from product sales are a function of the volumes produced, product quality, market prices, gas Btu content, as well as GP&T costs. GP&T costs are allocated across natural gas and NGLs based on revenue, which leads to heightened fluctuations in such cost allocations across periods. Our revenues from oil, natural gas and NGL sales do not include the effects of derivatives. Our revenues may vary significantly from period to period as a result of changes in the volume of production sold or changes in commodity prices. The following table presents the Company's oil and natural gas sales prior to and net of GP&T costs:
|
Year Ended December 31,
|
||||||||||||||
| 2025 | 2024 | |||||||||||||
|
Revenues:
|
(In thousands)
|
|||||||||||||
|
Oil sales, net
|
$ | 398,341 | $ | 408,935 | ||||||||||
|
Gas sales, gross
|
$ | 7,272 | $ | 2,480 | ||||||||||
|
Less: GP&T costs
|
(10,594) | (3,892) | ||||||||||||
|
Gas sales, net
|
$ | (3,322) | $ | (1,412) | ||||||||||
|
NGL sales, gross
|
$ | 44,159 | $ | 31,591 | ||||||||||
|
Less: GP&T costs
|
(47,198) | (29,313) | ||||||||||||
|
NGL sales, net
|
$ | (3,039) | $ | 2,278 | ||||||||||
|
Oil and natural gas sales, gross
|
$ | 449,772 | $ | 443,006 | ||||||||||
|
Less: GP&T costs
|
(57,792) | (33,205) | ||||||||||||
|
Oil and natural gas sales, net
|
$ | 391,980 | $ | 409,801 | ||||||||||
The Company's total oil and natural gas sales, net decreased $17.8 million, or 4%, for the year ended December 31, 2025, compared to the year ended December 31, 2024. The following tables summarize the effects of price, volume and GP&T cost changes on our revenues from oil, natural gas and NGLs:
Oil revenues
Oil revenues decreased by $10.6 million.
|
(In thousands)
|
||||||||
|
Oil sales, net for the year ended December 31, 2024
|
$ | 408,935 | ||||||
|
Price
|
(70,538) | |||||||
|
Volume
|
59,944 | |||||||
|
Oil sales, net for the year ended December 31, 2025
|
$ | 398,341 | ||||||
Our realized oil prices decreased by $11.15 per Bbl, which was the result of an $11.24 per Bbl decrease in the average WTI price. Daily oil volumes increased by 15% due to increased production from new wells turned to sales in our Red Lake field as well as the partial year contribution from the Silverback Acquisition.
Natural gas revenues
Natural gas revenues decreased by $1.9 million.
|
(In thousands)
|
||||||||
|
Gas sales, net for the year ended December 31, 2024
|
$ | (1,412) | ||||||
|
Price
|
3,405 | |||||||
|
Volume
|
1,387 | |||||||
| GP&T costs | (6,702) | |||||||
|
Gas sales, net for the year ended December 31, 2025
|
$ | (3,322) | ||||||
Our realized natural gas prices before GP&T costs increased by $0.29 per Mcf, which was the result of a $1.33 per Mcf increase in the average Henry Hub price, offset by higher allocated GP&T costs due to increased volumes in our Champions field resulting from a full year contribution of additional third party processing capacity that came online in mid-2024, higher volumes in our Red Lake field from new wells turned to sales as well as the partial year contribution from the Silverback Acquisition.
NGL revenues
NGL revenues decreased by $5.3 million.
|
(In thousands)
|
|||||
|
NGL sales, net for the year ended December 31, 2024
|
$ | 2,278 | |||
|
Price
|
(6,586) | ||||
|
Volume
|
19,154 | ||||
| GP&T costs | (17,885) | ||||
|
NGL sales, net for the year ended December 31, 2025
|
$ | (3,039) | |||
Our realized NGL prices before GP&T costs decreased by $2.76 per Bbl, or 13%, which was the result of an $11.24 per Bbl or 15% decrease in the average WTI price. GP&T costs increased due to increased volumes in our Champions field resulting from a full year contribution of additional third party processing capacity that came online in mid-2024, higher volumes in our Red Lake field from new wells turned to sales as well as the partial year contribution from the Silverback Acquisition.
Costs and Expenses
The following table presents the Company's operating costs and expenses and other (income) expenses:
| Year Ended December 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| Costs and Expenses: | (In thousands) | ||||||||||
| Lease operating expenses | $ | 87,506 | $ | 71,463 | |||||||
| Production and ad valorem taxes | $ | 29,052 | $ | 29,428 | |||||||
| Exploration costs | $ | 361 | $ | 2,595 | |||||||
| Depletion, depreciation, amortization and accretion | $ | 93,183 | $ | 74,900 | |||||||
| Impairment of oil and natural gas properties | $ | 1,214 | $ | 11,317 | |||||||
| Other impairments | $ | 1,607 | $ | 30,158 | |||||||
| Administrative costs | $ | 31,472 | $ | 26,551 | |||||||
|
Stock-based compensation
|
9,130 | 8,138 | |||||||||
| General and administrative expense | $ | 40,602 | $ | 34,689 | |||||||
| Transaction costs | $ | 5,176 | $ | 1,573 | |||||||
| Interest expense, net | $ | 31,364 | $ | 34,338 | |||||||
| (Gain) loss on derivatives, net | $ | (36,259) | $ | 1,665 | |||||||
| Loss from equity method investment | $ | 886 | $ | 721 | |||||||
| Gain on midstream sale | $ | (71,675) | $ | - | |||||||
| Income tax expense | $ | 48,123 | $ | 28,074 | |||||||
Lease Operating Expenses ("LOE")
LOE are the costs incurred in the operation and maintenance of producing properties. Expenses for electricity, compression, direct labor, saltwater disposal and materials and supplies comprise the most significant portion of our lease operating expenses. Certain operating cost components, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to our pumping equipment or surface facilities or subsurface maintenance result in increased production expenses in periods during which they are performed. Certain operating cost components, such as saltwater disposal associated with produced water, are variable and increase or decrease as hydrocarbon production levels and the volume of water disposal increases or decreases.
The Company's LOE increased by $16.0 million for the year ended December 31, 2025, compared to the year ended December 31, 2024. This was driven primarily by higher production volumes, including an $8.3 million increase due to higher production in our Red Lake field, a $7.2 million increase due to Silverback production added to our Red Lake field, and a $0.9 million increase in workovers.
Production and Ad Valorem Tax Expense
Production taxes are paid on produced oil, natural gas and NGLs based on a percentage of revenues at fixed rates established by federal, state or local taxing authorities. In general, the production taxes we pay correlate to changes in our oil, natural gas and NGL revenues. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and natural gas properties, which also trend with oil and natural gas prices and vary across the different counties in which we operate.
Production and ad valorem taxes decreased by $0.4 million for the year ended December 31, 2025, compared to the year ended December 31, 2024, primarily due to lower realized prices of $6.8 million and $1.5 million related to the Environment Protection Agency's WEC that was nullified in the first quarter of 2025, partially offset by $5.5 million due to increased production and $2.4 million due to the Silverback Acquisition.
Exploration Costs
Exploration costs consist of exploratory well expense, expiration of unproved leasehold, and geological and geophysical costs which include seismic survey costs. The following table presents the components of exploration costs:
| Year Ended December 31, | |||||||||||
| 2025 | 2024 | ||||||||||
|
(In thousands)
|
|||||||||||
|
Exploratory well expense
|
$ | - | $ | - | |||||||
|
Expiration of unproved leasehold
|
315 | 2,560 | |||||||||
| Geological and geophysical costs | 46 | 35 | |||||||||
| Total exploration costs | $ | 361 | $ | 2,595 | |||||||
Depletion, Depreciation, Amortization and Accretion Expense
DD&A expense is the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil, natural gas and NGLs. All costs incurred in the acquisition, exploration and development of properties (excluding costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes and overhead related to exploration activities) are capitalized. Capitalized costs are depleted using the units-of-production method.
Accretion expense relates to ARO. We record the fair value of the liability for ARO in the period in which the liability is incurred (at the time the wells are drilled or acquired) with the offset to property cost. The liability accretes each period until it is settled or the well is sold, at which time the liability is removed.
The following table presents the components of the Company's DD&A expense:
| Year Ended December 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| (In thousands) | |||||||||||
| Depletion | $ | 84,424 | $ | 71,260 | |||||||
| Accretion | 7,193 | 2,765 | |||||||||
|
Depreciation and amortization
|
1,566 | 875 | |||||||||
|
Total DD&A expense
|
$ | 93,183 | $ | 74,900 | |||||||
DD&A expense increased by $18.3 million for the year ended December 31, 2025, compared to the year ended December 31, 2024. The increase for the year ended December 31, 2025, was primarily due to higher production in our historical Red Lake and Champions fields, which increased depletion expense by approximately $12 million and $5 million, respectively, in addition to the inclusion of the Silverback Acquisition, which increased depletion expense by approximately $7 million, These increases were partially offset by a lower depletion rate in our Red Lake field, which decreased depletion expense by approximately $8 million due to reserve estimate revisions. Accretion increased $4 million as a result of higher plug-and-abandonment activity occurring on wells acquired in the New Mexico Acquisitions.
Impairments
Impairment of Oil and Natural Gas Properties
The cost of proved oil and natural gas properties are assessed on a field-by-field basis for impairment at least annually or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We compare the expected undiscounted future cash flows of the oil and natural gas properties to the carrying amount of the oil, natural gas and NGL properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we adjust the carrying amount of the oil and natural gas properties to estimated fair value.
During the year ended December 31, 2025, and 2024, the Company recognized a non-cash impairment loss on proved properties of $1.2 million and $1.8 million, respectively, relating to certain properties in New Mexico outside of the Company's acreage in the Red Lake field. Additionally, the Company recognized a non-cash impairment loss on proved properties of $9.5 million for the year ended December 31, 2024, relating to certain properties in Texas outside of the Company's acreage in the
Champions field that were sold as part of the Viking Sale. The 2025 and 2024 impairments were primarily driven by a reduction in well results and lower commodity prices.
Other Impairments
The Company recognized an additional non-cash impairment loss of $1.6 million for the year ended December 31, 2025 related to equipment from the EOR project that was intended to be repurposed for use in our conventional development programs. The Company also recognized an impairment loss of $30.2 million for the year ended December 31, 2024, which consisted of a non-cash impairment loss of $28.9 million related to the discontinuation of the EOR project, and a cash impairment loss of $1.3 million related a contract termination payment. The discontinuation of the Company's EOR project was in favor of redeploying the required future capital and repurposing certain assets for use in the Company's conventional vertical and horizontal development programs.
General and Administrative ("G&A") Expense
G&A expenses consist of administrative costs and stock-based compensation expense. Administrative costs include corporate overhead such as payroll and benefits for our staff, office costs, fees for professional services such as audit and legal services, technology costs, insurance and other. Stock-based compensation expense reflects costs associated with our stock granted to employees and members of our board of directors. G&A expenses are reported net of overhead recoveries.
For the year ended December 31, 2025, total G&A expense increased by $5.9 million, compared to the year ended December 31, 2024. Administrative costs increased by $4.9 million, which was primarily driven by increased employee headcount, including headcount retained as part of the Silverback Acquisition, resulting in higher compensation expenses, as well as transition costs from the Silverback Acquisition. Additional drivers of increased administrative costs included technology costs, professional services, office costs and insurance costs. Stock-based compensation expense increased by $1.0 million primarily due to an increase in outstanding equity awards.
Transaction Costs
Transaction costs represent costs incurred on successful or unsuccessful commercial transactions, business combinations or unsuccessful acquisitions. The transaction costs of $5.2 million for the year ended December 31, 2025, primarily related to the Silverback Acquisition. During the year ended December 31, 2024, the transaction costs of $1.6 million primarily related to the RPC Power joint venture and costs associated with the negotiation and closing of a long-term gas purchase agreement in addition to potential transactions that the Company evaluated but decided not to pursue further.
Interest Expense, net
Interest expense, net decreased by $3.0 million during the year ended December 31, 2025, when compared to the year ended December 31, 2024. The decrease in interest expense was primarily due to a lower average interest rate on the Credit Facility as well as a lower average balance on the Senior Notes.
Gain (Loss) on Derivatives, net
The Company recognizes settlements and changes in the fair value of our derivative contracts as a single component within other income (expense) in our consolidated statements of operations. We have oil and natural gas derivative contracts, including fixed price swaps, basis swaps and collars, that settle against various indices. The following table presents the components of the Company's gain (loss) on derivatives, net:
| Year Ended December 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| (In thousands) | |||||||||||
| Settlements on derivative contracts | $ | 16,615 | $ | 1,849 | |||||||
| Non-cash gain (loss) on derivatives | 19,644 | (3,514) | |||||||||
| Gain (loss) on derivatives, net | $ | 36,259 | $ | (1,665) | |||||||
Cash gains or losses on settled derivative contracts relate to contracts that settle during the period and are a function of the difference in settled versus contractual prices and the associated hedged volumes for each underlying commodity. Non-cash gains or losses on derivatives relate to unsettled contracts and are a function of changes in derivative fair values associated with fluctuations in the forward price curves for the commodities relative to contractual pricing and the associated hedged volumes for each underlying commodity for our derivative contracts outstanding.
Income Tax Expense
Current income taxes represent the amount the Company expects to owe to federal and state tax authorities in the current period, based on our taxable income. Deferred income taxes are provided to reflect the future tax consequences or benefits of differences between the tax basis of assets and liabilities and their reported amounts in the financial statements using enacted tax rates. See Note 12 - Income Taxes in the Company's consolidated financial statements in "Item 15. Exhibits and Financial Statement Schedules" for a full discussion of income taxes. Total income tax expense is summarized below:
| Year Ended December 31, | |||||||||||
| 2025 | 2024 | ||||||||||
| (In thousands) | |||||||||||
| Current income tax expense | $ | 36,771 | $ | 24,872 | |||||||
|
Deferred income tax expense
|
11,352 | 3,202 | |||||||||
| Total income tax expense | $ | 48,123 | $ | 28,074 | |||||||
| Effective income tax rate | 23.0% | 24.0% | |||||||||
The increase in our current income tax expense was due to the Midstream Sale, which increased our current tax liability by $16.5 million, partially offset by an increase in tax depreciation and depletion due to higher production and capital spending. The decrease in our effective income tax rate was primarily due to the federal marginal well tax credit.
Liquidity and Capital Resources
The business of exploring for, developing and producing oil and natural gas is capital intensive. Because oil, natural gas and NGL reserves are a depleting resource, we must make capital investments, like all upstream operators, to sustain and grow production. The Company's principal liquidity requirements are to finance our operations, fund capital expenditures, fund acquisitions and joint venture commitments, pay dividends and satisfy any indebtedness obligations. Cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and the significant capital expenditures required to more fully develop the Company's oil and natural gas properties. Historically, our primary sources of capital funding and liquidity have been our cash on hand, cash flow from operations, borrowings under our Credit Facility and the issuance of our Senior Notes. At times and as needed, we may also issue debt or equity securities, including through transactions under our shelf registration statement filed with the SEC. In April 2024, the Company issued equity securities and used the proceeds to finance an acquisition, repay outstanding debt and for general corporate purposes. We estimate the combination of the sources of capital discussed above will continue to be adequate to meet our short and long-term liquidity needs.
Cash on hand and operating cash flow can be subject to fluctuations due to trends and uncertainties that are beyond our control. Likewise, our ability to issue equity, debt and obtain credit facilities on favorable terms may be impacted by a variety of market factors as well as fluctuations in our results of operations.
For further discussion of risks related to our liquidity and capital resources, see "Item 1A. Risk Factors."
Working Capital
Working capital represents the funds available to meet day-to-day operational needs and is the difference in our current assets and our current liabilities. Working capital is an indication of liquidity and potential need for short-term funding. The change in our working capital requirements is driven generally by changes in accounts receivable, accounts payable, commodity prices, credit extended to, and the timing of collections from customers, the level and timing of spending for expansion activity, and the timing of debt maturities. Our working capital fluctuates as our drilling and completion activity changes with periods of higher and lower activity. We utilize our Credit Facility and cash on hand to manage the timing of cash
flows and fund short-term working capital deficits. At December 31, 2025, we had $290 million of undrawn capacity under our Credit Facility. The following table presents the components of working capital:
| Year Ended December 31, | ||||||||||||||
| 2025 | 2024 | |||||||||||||
| (In thousands) | ||||||||||||||
| Current Assets: | ||||||||||||||
| Cash | $ | 17,889 | $ | 13,124 | ||||||||||
| Accounts receivable, net | 41,045 | 44,411 | ||||||||||||
| Prepaid expenses | 7,763 | 1,592 | ||||||||||||
| Inventory | 7,929 | 5,734 | ||||||||||||
| Current derivative assets | 19,141 | 3,264 | ||||||||||||
| Total Current Assets | $ | 93,767 | $ | 68,125 | ||||||||||
|
Current Liabilities:
|
||||||||||||||
| Accounts payable | $ | 5,083 | $ | 13,937 | ||||||||||
| Accrued liabilities | 37,690 | 33,918 | ||||||||||||
| Revenue payable | 59,606 | 34,786 | ||||||||||||
| Current derivative liabilities | 37 | - | ||||||||||||
| Current portion of long-term debt | 20,000 | 20,000 | ||||||||||||
| Other current liabilities | 34,089 | 20,123 | ||||||||||||
| Total Current Liabilities | $ | 156,505 | $ | 122,764 | ||||||||||
|
Working Capital Deficit
|
$ | (62,738) | $ | (54,639) | ||||||||||
Our working capital deficit increased by $8.1 million primarily due to the Silverback Acquisition increasing our revenue payable and the Midstream Sale increasing our income tax payable, which was included in other current liabilities in our consolidated balance sheets, partially offset by an increase in our current derivative assets due to a decrease in crude oil pricing.
Cash Flows
The following table summarizes the Company's cash flows:
| Year Ended December 31, | ||||||||||||||
| 2025 | 2024 | |||||||||||||
| (In thousands) | ||||||||||||||
| Net cash provided by operating activities | $ | 212,539 | $ | 246,274 | ||||||||||
| Net cash used in investing activities | $ | (145,769) | $ | (147,838) | ||||||||||
| Net cash used in financing activities | $ | (62,005) | $ | (100,631) | ||||||||||
Operating Activities
Net cash provided by operating activities were $212.5 million for the year ended December 31, 2025, compared to $246.3 million for the year ended December 31, 2024, and primarily consisted of the following:
| Year Ended December 31, | ||||||||||||||
| 2025 | 2024 | |||||||||||||
| (In thousands) | ||||||||||||||
|
Total revenues, net
|
$ | 391,980 | $ | 410,181 | ||||||||||
|
Operating expenses (1)
|
$ | (153,252) | $ | (128,653) | ||||||||||
|
Advances from joint interest owners
|
$ | (6,828) | $ | 11,020 | ||||||||||
| Settlements on derivative contracts | $ | 16,615 | $ | 1,849 | ||||||||||
|
Interest paid, net of capitalized interest
|
$ | (28,214) | $ | (31,582) | ||||||||||
|
Tax liabilities paid, net of refunds
|
$ | (20,565) | $ | (18,084) | ||||||||||
(1)Operating expenses include LOE, production and ad valorem taxes, administrative costs, transaction costs and other minor operating expenses.
The decrease in net cash provided by operating activities was due primarily to lower revenues from a decrease in realized prices and higher operating expenses due to higher production volumes. Increased settlements on derivatives partially offset the decrease in revenues.
Investing Activities
Net cash flows used in investing activities were $145.8 million for the year ended December 31, 2025, compared to $147.8 million for the year ended December 31, 2024, and primarily consisted of the following:
| Year Ended December 31, | ||||||||||||||
| 2025 | 2024 | |||||||||||||
|
(In thousands)
|
||||||||||||||
| Additions to oil and natural gas properties | $ | (89,624) | $ | (98,490) | ||||||||||
|
Additions to midstream property and equipment
|
$ | (36,667) | $ | (10,964) | ||||||||||
| Net assets acquired in business combination | $ | (117,702) | $ | - | ||||||||||
| Acquisitions of oil and natural gas properties | $ | (2,161) | $ | (19,597) | ||||||||||
|
Disposition of midstream property and equipment
|
$ | 120,204 | $ | - | ||||||||||
| Contributions to equity method investment | $ | (15,750) | $ | (17,912) | ||||||||||
Capital expenditures for oil and natural gas properties decreased due to fewer wells drilled and lower facility costs. Additions to midstream property and equipment increased due to continued construction of the midstream project, which was subsequently sold as part of the Midstream Sale, generating cash inflows from the disposition. Net assets acquired in business combinations increased due to the Silverback Acquisition. Acquisitions of oil and natural gas properties decreased due to the 2024 New Mexico Acquisition with no comparable activity in 2025.
Financing Activities
Net cash flows used in financing activities were $62.0 million for the year ended December 31, 2025, compared to $100.6 million for the year ended December 31, 2024, and primarily consisted of the following:
| Year Ended December 31, | ||||||||||||||
| 2025 | 2024 | |||||||||||||
|
(In thousands)
|
||||||||||||||
| Repayments to Credit Facility, net | $ | (5,000) | $ | (70,000) | ||||||||||
| Repayments to Senior Notes, net of issuance costs | $ | (20,000) | $ | (20,000) | ||||||||||
|
Payment of cash dividends
|
$ | (33,325) | $ | (30,831) | ||||||||||
| Proceeds from issuance of common shares, net | $ | - | $ | 25,415 | ||||||||||
Net repayments under our Credit Facility decreased year over year. During 2025, we drew on our Credit Facility to fund the Silverback Acquisition, and for general working capital purposes, and subsequently repaid borrowings with proceeds from the Midstream Sale. During 2024, we drew on the Credit Facility to fund the 2024 New Mexico Acquisition, and for general working capital purposes, and subsequently repaid borrowings with excess cash flow. The proceeds from issuance of common shares in 2024 was attributable to equity securities issued in 2024 with no comparable activity in 2025.
Credit Facility and Senior Notes
The Company's borrowing base on our Credit Facility was $400 million with outstanding borrowings of $110 million at December 31, 2025, representing available borrowing capacity of $290 million.
On February 22, 2023, the Company amended our Credit Facility to, among other things, allow for the issuance of unsecured Senior Notes of up to $200 million. On April 3, 2023, and concurrent with the closing of the 2023 New Mexico Acquisition, the Company entered into the fourteenth amendment to the Credit Facility to, among other things, increase the maximum facility amount to $1.0 billion and the borrowing base from $225 million to $325 million, resulting in the addition of new lenders to the lending group. On November 14, 2023, through the semi-annual redetermination process and fifteenth amendment, the Company increased our borrowing base from $325 million to $375 million, resulting in the addition of two new lenders and the exit of one lender. On December 13, 2024, the Company entered into the sixteenth amendment to the Credit Facility to, among other things, extend the stated maturity date from April 2026 to December 2028 (or if any Senior Notes are then outstanding, the date that is 181 days prior to the earliest stated maturity date of such Senior Notes, in this case October 2027) and increase the borrowing base from $375 million to $400 million, which was reaffirmed in December 2025 with the removal of the natural gas hedging requirement. Substantially all of the Company's assets are pledged to secure the Credit Facility.
During the year ended December 31, 2023, the Company issued $200 million in principal amount of Senior Notes with a maturity date of April 2028. The proceeds from the Senior Notes were used to finance the 2023 New Mexico Acquisition. The Senior Notes had a principal balance of $145 million as of December 31, 2025.
See Note 10 - Long-Term Debt in the Company's consolidated financial statements in "Item 15. Exhibits and Financial Statement Schedules" for a full discussion of our long-term debt.
Dividends
For the year ended December 31, 2025, the Company recognized quarterly dividends totaling approximately $33.6 million, with $33.3 million paid in cash and $0.3 million accrued for the holders of unvested restricted stock awards. For the years ended December 31, 2025, and 2024, the Company paid cash dividends of approximately $0.8 million and $0.7 million, respectively, to holders of restricted stock upon vesting. See Note 11 - Shareholders' Equity in the Company's consolidated financial statements in "Item 15. Exhibits and Financial Statement Schedules" for further discussion.
Contractual Obligations
As of December 31, 2025, the Company had a remaining volume commitment of less than five years with Stakeholder. The Company also had natural gas delivery commitments under the A&R Tolling Agreement and a remaining equity commitment under the Second Amendment to the A&R LLC Agreement to fund our portion of the capital budget for the RPC Power joint venture. Further, the Company entered into the A&R Gas Purchase Agreement that required an acreage dedication and a
minimum volume commitment to Targa for a significant portion of our natural gas production in New Mexico. This agreement is expected to commence before the end of 2026. See Note 15 - Commitments and Contingencies in the Company's consolidated financial statements in "Item 15. Exhibits and Financial Statement Schedules" for a full discussion of our commitments and contingencies.
Critical Accounting Estimates
The preparation of financial statements requires the Company to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.
Changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates and assumptions used in preparation of the Company's consolidated financial statements and it is at least reasonably possible these estimates could be revised in the near term and these revisions could be material.
Method of Accounting for Oil and Natural Gas Properties
We utilize the successful efforts method of accounting for our oil and natural gas exploration and development activities which requires management's assessment of the proper designation of wells and associated costs as developmental or exploratory. This classification assessment is dependent on the determination and existence of proved reserves, which is a critical estimate discussed in the section below. The classification of developmental and exploratory costs has a direct impact on the amount of costs we initially recognize as exploration expense or capitalize, then subject to DD&A calculations and impairment assessments and valuations.
Once a well is drilled, the determination that proved reserves have been discovered may take considerable time and requires both judgment and application of industry experience. At the end of each quarter, the status of all suspended exploratory drilling costs are reviewed to determine whether the costs should continue to remain capitalized or shall be expensed. When making this determination, current activities, near-term plans for additional exploratory or appraisal drilling and the likelihood of reaching a development program is considered.
Similar to the evaluation of suspended exploratory well costs, costs for unproved leasehold, for which reserves have not been proven, must also be evaluated for continued capitalization or impairment. At the end of each quarter, unproved leasehold costs are assessed for impairment by considering future drilling plans, drilling activity results, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. At December 31, 2025, the Company had approximately $156.0 million of unproved leasehold. Of the remaining unproved leasehold costs at December 31, 2025, approximately $3.4 million is scheduled to expire in 2026. The Company expects to renew or extend these leases in 2026. If our drilling is not successful, this leasehold could become partially or entirely impaired.
Once a well is drilled, capitalized well costs for drilling and completion activities must be evaluated at least yearly or whenever facts and circumstances indicate a decline in the recoverability of their carrying value may have occurred. At the end of each year, the undiscounted future cash flows are compared to the carrying value on a field basis to evaluate if the carrying value is recoverable. If the carrying value is not recoverable, the Company will compare the carrying value of the asset to its fair value and recognize any impairment loss in the period. Significant inputs and judgments are used in determining the fair value of the assets. The Company utilizes a discounted cash flow model in order to estimate fair value by modeling the present value of future cash flows, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with the expected cash flow projected.
During the year ended December 31, 2025, and 2024, the Company recognized a non-cash impairment loss on proved properties of $1.2 million and $1.8 million, respectively, relating to certain properties in New Mexico outside of the Company's acreage in the Red Lake field. Additionally, the Company recognized a non-cash impairment loss on proved properties of $9.5 million for the year ended December 31, 2024, relating to certain properties in Texas outside of the Company's acreage in the Champions field that were sold as part of the Viking Sale. The 2025 and 2024 impairments were primarily driven by a reduction in well results and lower commodity prices.
See Note 7 - Fair Value Measurements in the Company's consolidated financial statements in "Item 15. Exhibits and Financial Statement Schedules" for a full discussion of our impairment analysis.
Oil and Natural Gas Reserves
Our estimates of proved and proved developed reserves are a major component of our depletion calculation. Additionally, our proved reserves represent the element of these calculations that require the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. The process of estimating oil, natural gas and NGL reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data. A third-party reservoir engineering firm prepares our reserve report, which the estimates are based off of technical and economic data including, but not limited to, well test data, production data, historical price and cost information, and property ownership interests.
The passage of time provides more qualitative information regarding estimates of reserves, when revisions are made to prior estimates to reflect updated information. The data for a given reservoir may also change substantially over time as a result of numerous factors, including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions.
Business Combinations
The 2023 New Mexico Acquisition and the Silverback Acquisition resulted in the Company acquiring assets and assuming liabilities in transactions accounted for as business combinations. In connection with these acquisitions, we allocated the purchase price consideration to the assets acquired and liabilities assumed based on estimated fair values as of the acquisition date.
We made a number of assumptions in estimating the fair value of assets acquired and liabilities assumed in these acquisitions. The most significant assumptions relate to the estimated fair values of proved and unproved oil and gas properties. The fair value of identifiable assets acquired and liabilities assumed is determined based on various valuation techniques, including market prices, discounted cash flow analysis, and independent appraisals. Significant judgments and assumptions are inherent in these valuation techniques and include, among other things, estimates of reserves, estimates of future commodity prices, expected development costs, lease operating costs and the discount rate that reflects the risk of the underlying cash flow estimates. In addition, the earnout payments in connection with the Silverback Acquisition were valued using a Monte Carlo simulation model which involved modeling the potential earnout payments over numerous scenarios based on WTI futures prices.
Estimated fair values assigned to assets acquired can have a significant impact on future results of operations presented in the Company's financial statements. A higher fair value assigned to a property results in higher DD&A expense, which results in lower net income. In the event that future commodity prices or reserve quantities are lower than those used as inputs to determine estimates of acquisition date fair values, the likelihood increases that certain costs may be determined to not be recoverable.
See Note 4 - Acquisitions and Divestitures in the Company's consolidated financial statements in "Item 15. Exhibits and Financial Statement Schedules" for a full discussion of our acquisitions.
See Note 3 - Summary of Significant Accounting Policies in the Company's consolidated financial statements in "Item 15. Exhibits and Financial Statement Schedules" for a full discussion of our significant accounting policies.
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