Prairie Operating Co. press release

Prairie Operating Co. Announces Year End 2025 Results

2026-03-30

NASDAQ - Nasdaq Stock Market · Oil · Natural Gas · Natural Gas Liquids · United States · Corporate Finance

2025 Total Revenue of $241.6 million (approximately $315.0 million including Bayswater), an increase of approximately 3,000% year-over-year Record Adjusted EBITDA(1)of $155.5 million (approximately $220.0 million including Bayswater), an increase of over 975% year-over-year Approximately 3,900% increase in annual production to 18,500 net Boe/d (approximately 24,000 Boe/d including Bayswater) (50% oil / 73% liquids) Current production rate of approximately 28,000 net Boe/d Reached agreement to extend grant of Series F Preferred equity anniversary warrants

HOUSTON, March 30, 2026 (GLOBE NEWSWIRE) -- Prairie Operating Co. (Nasdaq: PROP) (the “Company,” “Prairie,” “we,” “our,” or “us”) – an independent energy company engaged in the development and acquisition of oil, natural gas, and natural gas liquids (“NGL”) resources in the Denver-Julesburg (DJ) Basin – today announced its financial and operational results through and subsequent to the year ended December 31, 2025.

KEY HIGHLIGHTS

Record total production of 6.75 million of barrels of oil equivalent (“MMBoe”) (approximately 73% liquids). Proved reserves of 121,119 MBoe, 43% of which are proved undeveloped with discounted future net cash flows of $851.7 million, PV-10(1)of $1,219.8 million. Expanded hedging program, securing favorable commodity pricing through 2029. Closed and completed transition services period for $602.75 million acquisition of assets from Bayswater Exploration & Production. Completed six additional complementary acquisitions, adding approximately 44,000 net acres at attractive metrics. Exited 2025 with a current production rate of approximately 28,000 net Boe/d, reflecting the strength of the Company’s asset base and the impact of development activity during the year.

(1) EBITDA and PV-10 are Non-GAAP measures, refer to “Non-GAAP Financial Measures” for reconciliations of GAAP to non-GAAP financial measures used throughout this press release.

From Rich Frommer, Interim Chief Executive Officer and President:

“2025 marked a transformational year for Prairie. We materially scaled production, expanded margins, fully integrated the Bayswater assets, and strengthened our balance sheet while maintaining capital discipline and operational excellence.”

“Our team delivered record production and Adjusted EBITDA(1), giving us strong momentum entering 2026. With a deep inventory of high-quality drilling locations, expanded hedge protection, and growing scale in the DJ Basin, we believe Prairie is well positioned to execute on its strategy and create long-term shareholder value.”

YEAR END FINANCIAL RESULTS SUMMARY

Full Year 2025 Highlights

Revenue of $241.6 million (approximately $315.0 million including Bayswater), driven by realized prices (excluding hedges) of $59.91 per barrel for oil, $18.16 per barrel for NGLs, and $0.88 per Mcf for natural gas. Net loss attributable to common stockholders of $60.9 million, or $1.35 basic loss per share. Adjusted EBITDA(1)of $155.5 million (approximately $220.0 million including Bayswater) compared to $(17.7) million for the year ended December 31, 2024. Capital expenditures incurred of $183.4 million, approximately 35% below midpoint of guidance. Net cash provided by operating activities of $153.9 million. Proved reserves of 121,119 MBoe, 43% of which are proved undeveloped. Standardized measure of discounted future net cash flows of $851.7 million, PV-10(1)of $1,219.8 million.

(1) Adjusted EBITDA and PV-10 are Non-GAAP measures, refer to “Non-GAAP Financial Measures” for reconciliations of GAAP to non-GAAP financial measures used throughout this press release.

OPERATIONS UPDATE

Operationally, 2025 marked a significant step forward for Prairie as the Company completed the transition period following the Bayswater acquisition and assumed full operational control of those assets.

On April 1, 2025, we launched development at our Rusch pad in Weld County, which consists of 11 two-mile lateral wells. The Rusch wells came online late in September 2025 with initial average oil and natural gas production measured before any deductions for fuel, flare, or vented volumes (“two-stream”) gross production of 475 Boe/d.

On April 28, 2025, we announced plans to begin completions on nine previously drilled but uncompleted wells acquired in the Bayswater Acquisition. Completion activities at the Opal/Coalbank pad began in May 2025, and the wells came online mid-July 2025 with initial average two-stream gross production of 725 Boe/d.

On June 1, 2025, we moved the drilling rig to our Noble pad in Weld County, which consists of seven wells. The Noble wells came online in November 2025 with initial average two-stream gross production of 550 Boe/d.

In September 2025, we moved the drilling rig to the recently acquired Simpson pad in Weld County, which consists of six wells. Three Simpson wells came online in December 2025, and the remaining wells came online in January 2026 with initial average two-stream gross production of 500 Boe/d.

In December 2025, we moved the drilling rig to the Blehm pad and then the Schneider pad, both in Weld County, consisting of ten wells. Completion activities at the Blehm and Schneider pads are ongoing, with first production expected early in the second quarter of 2026.

At the end of 2025, we moved the drilling rig to the Elder East and West pad, which consists of nine wells. Drilling at this pad is expected to be completed imminently.

YEAR END 2025 RESULTS

Key Financial Highlights

| (In thousands, except per share amounts) | | Year Ended December 31, 2025 | | | | Total revenues | | $ | 241,648 | | | Net loss attributable to common stockholders | | $ | (60,907 | ) | | Loss per share – basic & diluted | | $ | (1.35 | ) | | Adjusted EBITDA | | $ | 155,535 | | | Capital expenditures | | $ | 183,352 | | | | | | | |

RESERVES

Our reserve estimates as of December 31, 2025, are based on a reserve report prepared by Cawley, Gillespie & Associates Inc. (“CG&A”) in accordance with the rules and regulations of the SEC in Regulation S-X, Rule 4-10, and do not include probable or possible reserves. All of our proved reserves presented below are located in the DJ Basin.

The following table presents our estimated proved reserves by category, the standardized measure of discounted future net cash flows, PV-10, and the prices used in the calculation of net proved reserves estimates for the year ended December 31, 2025:

| | | Year Ended December 31, 2025 | | | | Net reserve volumes: | | | | | | Proved developed producing: | | | | | | Oil (MBbls) | | | 27,900 | | | Natural gas (MMcf) | | | 122,975 | | | NGL (MBbls) | | | 17,974 | | | Total (MBoe)(1) | | | 66,370 | | | | | | | | | Proved developed non-producing: | | | | | | Oil (MBbls) | | | 1,406 | | | Natural gas (MMcf) | | | 2,258 | | | NGL (MBbls) | | | 330 | | | Total (MBoe)(1) | | | 2,112 | | | | | | | | | Proved undeveloped: | | | | | | Oil (MBbls) | | | 30,725 | | | Natural gas (MMcf) | | | 70,041 | | | NGL (MBbls) | | | 10,238 | | | Total (MBoe)(1) | | | 52,637 | | | | | | | | | Total proved: | | | | | | Oil (MBbls) | | | 60,031 | | | Natural gas (MMcf) | | | 195,274 | | | NGL (MBbls) | | | 28,542 | | | Total (MBoe)(1) | | | 121,119 | | | | | | | | | Reserves data (in thousands): | | | | | | Standardized measure of discounted future net cash flows | | $ | 851,702 | | | PV-10(2) | | $ | 1,219,814 | | | | | | | | | SEC Prices(3): | | | | | | Oil (per Bbl) | | $ | 65.34 | | | Natural gas (per Mcf) | | $ | 3.39 | | | NGL (per Bbl) | | $ | 19.28 | |

| (1) | Assumes a ratio of 6 MMcf of natural gas per MBoe. | | (2) | PV-10 is a financial measure not presented in accordance with U.S. GAAP. PV-10 is derived from the Standardized Measure, which is the most directly comparable GAAP financial measure for proved reserves. PV-10 is a computation of the Standardized Measure on a pre-tax basis and is equal to the Standardized Measure at the applicable date, before deducting future income taxes discounted at 10%. | | (3) | Our estimated proved reserves and the related net revenues were determined using the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December (“SEC Prices”). The SEC Prices are adjusted for treating costs and/or crude quality and gravity corrections. |

REVENUE AND PRODUCTION

Revenue for the year ended December 31, 2025 was $241.6 million, $204.0 million related to oil. Production for the year ended December 31, 2025 was 6,748 MBoe and was comprised of approximately 50% oil (approximately 73% liquids).

| | | Year Ended December 31, 2025(1) | | | | Revenues (in thousands) | | | | | | Oil revenue | | $ | 204,040 | | | Natural gas revenue | | | 9,472 | | | NGL revenue | | | 28,136 | | | Total revenues | | $ | 241,648 | | | | | | | | | Production: | | | | | | Oil (MBbls) | | | 3,406 | | | Natural gas (MMcf) | | | 10,753 | | | NGL (MBbls) | | | 1,550 | | | Total production (MBoe)(2) | | | 6,748 | | | | | | | | | Average sales volumes per day (Boe/d) | | | 18,487 | | | | | | | | | Average realized price (excluding effects of derivatives): | | | | | | Oil (per MBbl) | | $ | 59.91 | | | Natural gas (per MMcf) | | $ | 0.88 | | | NGL (per MBbl) | | $ | 18.16 | | | Average realized price (per MBoe) | | $ | 35.81 | | | | | | | | | Average realized price (including effects of derivatives): | | | | | | Oil (per MBbl) | | $ | 63.87 | | | Natural gas (per MMcf) | | $ | 1.65 | | | NGL (per MBbl) | | $ | 17.93 | | | Average price (per MBoe) | | $ | 38.98 | | | | | | | | | Average NYMEX prices: | | | | | | WTI (per MBbl) | | $ | 65.39 | | | Henry Hub (per MMBtu) | | $ | 3.51 | |

| (1) | Total revenues and production for the year ended December 31, 2025, include revenue and production volumes from the assets acquired from Bayswater beginning on March 26, 2025, the closing date of the acquisition, through December 31, 2025. | | (2) | MBoe is calculated using six MMcf of natural gas equivalent to one MBbl of oil. |

OPERATING COSTS

| (In thousands, except per Boe amounts) | | Year Ended December 31, 2025(1) | | | | Lease operating expenses | | $ | 41,411 | | | Lease operating expenses per Boe | | $ | 6.14 | | | | | | | | | Transportation and processing | | $ | 8,910 | | | Transportation and processing per Boe | | $ | 1.32 | | | | | | | | | Ad valorem and production taxes(2) | | $ | 21,231 | | | Ad valorem and production taxes per Boe | | $ | 3.15 | | | | | | | | | General and administrative expenses(3) | | $ | 50,614 | | | General and administrative expenses per Boe | | $ | 7.50 | |

| (1) | Total operating expenses for the year ended December 31, 2025, include operating expenses for the assets acquired from Bayswater beginning on March 26, 2025, the closing date of the acquisition, through December 31, 2025. Operating expenses per Boe for the year ended December 31, 2025 are calculated over production volumes which include volumes from the assets acquired from Bayswater beginning on March 26, 2025, the closing date of the acquisition, through December 31, 2025. | | (2) | Ad valorem and production taxes payable for the year ended December 31, 2025 includes the quarterly Colorado production fee of $1.7 million. | | (3) | General and administrative expenses for the year ended December 31, 2025 includes non-cash long-term incentive compensation expenses of $14.8 million. |

ACQUISITIONS AND CAPITAL EXPENDITURES

| (In thousands) | | Year Ended December 31, 2025 | | | | Cash paid for Bayswater asset purchase | | $ | 459,593 | | | Capital expenditures – cash | | $ | 177,700 | | | Other asset and leasehold purchases(1) | | $ | 19,428 | |

| (1) | Other asset and leasehold purchases for the year ended December 31, 2025 includes cash paid for Edge acquisition, the third Exok acquisition, and the Summit and Crown acquisitions. |

Liquidity and Capital Resources

As of December 31, 2025, we had approximately $109.0 million of liquidity, primarily consisting of borrowings available under our Credit Facility. As of December 31, 2025, the Credit Facility had a borrowing base of $475.0 million and aggregate elected commitments of $475.0 million.

2026 UPDATED GUIDANCE

Prairie initiates full-year guidance for 2026 as follows:

● Average Daily Production: 25,500 – 27,500 Boe/d. ● Capital Expenditures: $200.0 million – $220.0 million. ● Adjusted EBITDA(1): $240.0 million – $260.0 million.

(1)Adjusted EBITDA is a Non-GAAP measure, refer to “Non-GAAP Financial Measures” for reconciliations of GAAP to non-GAAP financial measures used throughout this press release.

COMMODITY HEDGES

The following table reflects contracted volumes and weighted average prices we will receive under the terms of our derivative contracts as of December 31, 2025:

| | | Settling January 1, 2026 through December 31, 2026 | | | Settling January 1, 2027 through December 31, 2027 | | | Settling January 1, 2028 through December 31, 2028 | | | | | | Crude Oil Swaps: | | | | | | | | | | | | | | Notional volume (Bbls) | | | 4,230,866 | | | | 3,306,753 | | | | 1,515,007 | | | Weighted average price ($/Bbl) | | $ | 62.36 | | | $ | 62.03 | | | $ | 61.60 | | | Natural Gas Swaps: | | | | | | | | | | | | | | Notional volume (MMBtus) | | | 13,420,634 | | | | 11,882,126 | | | | 4,406,357 | | | Weighted average price ($/MMBtu) | | $ | 4.08 | | | $ | 4.07 | | | $ | 4.00 | | | Ethane Swaps: | | | | | | | | | | | | | | Notional volume (Bbls) | | | 288,956 | | | | 232,375 | | | | 51,809 | | | Weighted average price ($/Bbl) | | $ | 11.54 | | | $ | 11.05 | | | $ | 11.28 | | | Propane Swaps: | | | | | | | | | | | | | | Notional volume (Bbls) | | | 509,724 | | | | 417,744 | | | | 94,220 | | | Weighted average price ($/Bbl) | | $ | 26.36 | | | $ | 26.51 | | | $ | 26.00 | | | Iso Butane Swaps: | | | | | | | | | | | | | | Notional volume (Bbls) | | | 63,185 | | | | 50,812 | | | | 11,328 | | | Weighted average price ($/Bbl) | | $ | 33.92 | | | $ | 30.22 | | | $ | 29.63 | | | Normal Butane Swaps: | | | | | | | | | | | | | | Notional volume (Bbls) | | | 174,809 | | | | 140,580 | | | | 31,343 | | | Weighted average price ($/Bbl) | | $ | 35.24 | | | $ | 31.37 | | | $ | 30.37 | | | Pentane Plus Swaps: | | | | | | | | | | | | | | Notional volume (Bbls) | | | 130,321 | | | | 104,802 | | | | 23,366 | | | Weighted average price ($/Bbl) | | $ | 53.05 | | | $ | 52.40 | | | $ | 52.49 | | | | | | | | | | | | | | | |

During the first quarter of 2026, we executed a portfolio of hedges securing the following weighted-average prices through the indicated periods:

| | | Settling January 1, 2026 through December 31, 2026 | | | Settling January 1, 2027 through December 31, 2027 | | | Settling January 1, 2028 through December 31, 2028 | | | Settling January 1, 2029 through June 30, 2029 | | | | | | | Crude Oil Swaps: | | | | | | | | | | | | | | | | | | Notional volume (Bbls) | | | 695,518 | | | | 960,750 | | | | 861,300 | | | | 210,000 | | | Weighted average price ($/Bbl) | | $ | 65.33 | | | $ | 63.49 | | | $ | 62.94 | | | $ | 61.57 | | | Natural Gas Swaps: | | | | | | | | | | | | | | | | | | Notional volume (MMBtus) | | | 600,000 | | | | 1,600,000 | | | | 1,200,000 | | | | 400,000 | | | Weighted average price ($/MMBtu) | | $ | 4.05 | | | $ | 4.07 | | | $ | 4.11 | | | $ | 4.11 | | | Ethane Swaps: | | | | | | | | | | | | | | | | | | Notional volume (Bbls) | | | 98,985 | | | | 168,300 | | | | 168,300 | | | | — | | | Weighted average price ($/Bbl) | | $ | 10.63 | | | $ | 10.21 | | | $ | 9.55 | | | $ | — | | | Propane Swaps: | | | | | | | | | | | | | | | | | | Notional volume (Bbls) | | | 64,175 | | | | 104,940 | | | | 104,940 | | | | — | | | ted average price ($/Bbl) | | $ | 30.07 | | | $ | 28.22 | | | $ | 25.87 | | | $ | — | | | Iso Butane Swaps: | | | | | | | | | | | | | | | | | | Notional volume (Bbls) | | | 14,070 | | | | 23,760 | | | | 23,760 | | | | — | | | Weighted average price ($/Bbl) | | $ | 39.36 | | | $ | 35.10 | | | $ | 31.32 | | | $ | — | | | Normal Butane Swaps: | | | | | | | | | | | | | | | | | | Notional volume (Bbls) | | | 25,795 | | | | 43,560 | | | | 43,560 | | | | — | | | Weighted average price ($/Bbl) | | $ | 37.99 | | | $ | 33.81 | | | $ | 30.35 | | | $ | — | | | Pentane Plus Swaps: | | | | | | | | | | | | | | | | | | Notional volume (Bbls) | | | 31,475 | | | | 55,440 | | | | 55,440 | | | | — | | | Weighted average price ($/Bbl) | | $ | 60.06 | | | $ | 55.05 | | | $ | 52.94 | | | $ | — | |

NON-GAAP FINANCIAL MEASURES

This press release contains Adjusted EBITDA and PV-10, which are financial measures not calculated or presented in accordance with GAAP. These supplemental non-GAAP financial measures are used by management and external users of our financial statements, such as investors, lenders, and rating agencies and may not be comparable to similarly titled measures reported by other companies.

ADJUSTED EBITDA

Adjusted EBITDA is used by management to evaluate the performance of our business, make operational decisions, and assess our ability to generate cashflows. Management believes Adjusted EBITDA provides investors with helpful information to better understand the underlying performance trends of our business, facilitate period-to-period comparisons, and assess the company’s operating results.

Adjusted EBITDA is derived from net income (loss) from continuing operations and is adjusted for income tax expense, depreciation, depletion, and amortization, accretion of asset retirement obligations, abandonment and impairment of unproved properties, non-cash stock-based compensation, interest expense, net, non-cash loss on adjustment to fair value – embedded derivatives, debt, and warrants, loss on debt issuance, unrealized gain on derivatives, and litigation settlement expense, all as applicable. We adjust net income (loss) from continuing operations for the items listed above to arrive at Adjusted EBITDA because these amounts can vary substantially between periods and companies within our industry depending upon accounting methods, book values of assets, capital structures, and the method by which assets were acquired. Adjusted EBITDA has limitations as an analytical tool, including that it excludes certain items that affect our reported financial results. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income calculated in accordance with GAAP or as an indicator of our operating performance or liquidity. Additionally, our calculation of Adjusted EBITDA may not be comparable to similarly titled measures used by other companies.

The following table presents the reconciliation of Net income (loss) from continuing operations to Adjusted EBITDA for the years indicated:

| | | Year Ended December 31, | | | | | | | | | | 2025(1) | | | 2024 | | | | | | | (In thousands) | | | | | | | | Net income (loss) from continuing operations reconciliation to Adjusted EBITDA: | | | | | | | | | | Net income (loss) from continuing operations | | $ | 32,051 | | | $ | (39,867 | ) | | Adjustments: | | | | | | | | | | Depreciation, depletion, and amortization | | | 48,916 | | | | 427 | | | Accretion of asset retirement obligations | | | 247 | | | | 6 | | | Abandonment and impairment of unproved properties(2) | | | 3,409 | | | | — | | | Non-cash stock-based compensation | | | 14,764 | | | | 8,377 | | | Interest expense, net | | | 27,471 | | | | 562 | | | Non-cash loss on adjustment to fair value – embedded derivatives, debt, and warrants(3) | | | 63,341 | | | | 5,358 | | | Non- cash loss on issuance of debt(4) | | | — | | | | 3,039 | | | Unrealized (gain) loss on derivatives | | | (57,834 | ) | | | 4,395 | | | Litigation settlement expense | | | 1,516 | | | | — | | | Income tax expense(5) | | | 21,654 | | | | — | | | Adjusted EBITDA | | $ | 155,535 | | | $ | (17,703 | ) |

| (1) | Net income (loss) from continuing operations for the year ended December 31, 2025 includes revenue and related expenses attributable to the assets acquired from Bayswater beginning on March 26, 2025, the closing date of the acquisition, through December 31, 2025. | | (2) | Reflects the abandonment of unproved locations which we have deemed non-core and allowed to expire. | | (3) | Reflects the changes in the fair values of the financial instruments measured at fair value on a recurring basis. | | (4) | Reflects the loss recognized for the issuance of the Subordinated Note and the Subordinated Note Warrants in the third quarter of 2024. | | (5) | Reflects deferred income tax expense recognized for the year ended December 31, 2025. | | | |