FOURTH QUARTER 2025 HIGHLIGHTS
Averaged 35.5 MBoe/d of total equivalent production (oil production of 20.1 MBbls/d)
Generated $65 million of operating cash flow, $85 million of net income, $66 million of Adjusted EBITDAX(1), $1 million of Total Free Cash Flow(1) and $17 million of Upstream Free Cash Flow(1)
Incurred total accrual (activity-based) capital expenditures before acquisitions of $50 million ($28 million for upstream)
Sold all of our membership interests in Dovetail Midstream LLC, a wholly owned subsidiary of the Company that held certain midstream infrastructure projects in Eddy County, New Mexico for total cash consideration of $123 million, with 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 ("Midstream Sale")
Reduced debt outstanding by $120 million with a year-end debt-to-Adjusted EBITDAX(1) ratio of 1.0x(2)
Announced the authorization of a stock repurchase program of up to $100 million of the currently outstanding shares of the Company's common stock
FULL-YEAR 2025 HIGHLIGHTS
Averaged 29.2 MBoe/d of total equivalent production (oil production of 17.3 MBbls/d)
Generated $213 million of operating cash flow, $161 million of net income, $261 million of Adjusted EBITDAX(1), $81 million of Total Free Cash Flow(1) and $117 million of Upstream Free Cash Flow(1)
Incurred total accrual (activity-based) capital expenditures before acquisitions of $120 million ($83 million for upstream)
Closed on the acquisition of Silverback Exploration II, LLC and its subsidiaries ("Silverback") for $120 million in cash plus contingent consideration, subject to final purchase price adjustments
Increased the dividend on our common stock in October 2025 by 5% to $0.40 quarterly and $1.60 annually
2026 GUIDANCE HIGHLIGHTS
Full-year 2026 guidance for total production of 35.0 - 37.0 MBoe/d (oil production of 21.0 - 22.0 MBbls/d)
Full-year 2026 guidance for activity-based capital expenditures before acquisitions of $190 - 210 million
Bobby Riley, Chairman of the Board and Chief Executive Officer commented, "2025 was a transformational year for Riley Permian, as we made significant progress across key strategic initiatives, including inventory expansion, infrastructure build‑out, and balance sheet improvement. The groundwork laid in 2025 positions the company for a more active and value‑enhancing development program in 2026 and beyond."
____________________
(1)
A non-GAAP financial measure as defined and reconciled in the supplemental financial tables available on the Company's website at www.rileypermian.com.
(2)
Debt leverage ratio based on principal debt outstanding as of December 31, 2025, divided by full-year Adjusted EBITDAX(1).
OPERATIONS AND DEVELOPMENT ACTIVITY UPDATE
The tables below provide a summary of our operated well activity and production by state:
Three Months Ended December 31, 2025
Year Ended December 31, 2025
Gross(1)
Net(2)
Gross(1)
Net(2)
Wells Drilled
Texas
8
8.0
18
18.0
New Mexico
—
—
—
—
Total
8
8.0
18
18.0
Wells Completed
Texas
5
5.0
12
12.0
New Mexico
—
—
10
6.3
Total
5
5.0
22
18.3
Wells Turned to Sales
Texas
3
3.0
10
10.0
New Mexico
—
—
10
6.3
Total
3
3.0
20
16.3
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(1) Gross wells are the total number of operated wells in which the Company has an interest
(2) Net wells are gross wells multiplied by our fractional working interest
Average Daily Production by State
Three Months Ended December 31,
Year Ended December 31,
2025
2024
2025
2024
Combined
Texas
19.4
17.7
17.6
15.7
New Mexico
16.1
7.3
11.6
6.8
Total (MBoe/d)
35.5
25.0
29.2
22.5
Oil
Texas
11.9
12.4
11.3
11.7
New Mexico
8.2
3.5
6.0
3.4
Total (MBbls/d)
20.1
15.9
17.3
15.1
FOURTH QUARTER 2025 FINANCIAL RESULTS
Revenues totaled $97 million, net cash provided by operating activities was $65 million and net income was $85 million, or $4.02 per diluted share.
On a non-GAAP basis, Adjusted EBITDAX(1) was $66 million, cash flow from operations before changes in working capital(1) was $35 million, Total Free Cash Flow(1) was $1 million and Adjusted Net Income(1) was $22 million, or $1.01 per diluted share.
Average realized prices, before derivative settlements, were $57.18 per barrel of oil, $(0.86) per Mcf of natural gas and $(6.67) per barrel of natural gas liquids. The Company reported a $21 million gain on derivatives, net, which included an $8 million realized gain on settlements.
Operating expenses included lease operating expense ("LOE") of $23 million, or $7.16 per Boe, administrative costs of $8 million, or $2.42 per Boe, and production and ad valorem taxes of $8 million or $2.44 per Boe.
The Company incurred $50 million in total accrued capital expenditures ($28 million for upstream). On a cash basis, the Company had total capital expenditures of $51 million ($35 million for upstream).
We recognized a pre-tax gain of $72 million from the Midstream Sale, net of $3 million in transaction costs. As a result, we incurred $16 million in corresponding income tax liability. Total FCF of $1 million excludes this tax impact.
The Company sold its interest in oil and natural gas properties in Texas outside of the Company's acreage in Yoakum County for 250,000 shares of the Company's common stock, which were subsequently retired, and which led to a reduction to additional paid-in-capital of $10 million.
The Company reduced total debt by $120 million, including a principal reduction of $115 million on the Credit Facility and $5 million on the Senior Notes. As of December 31, 2025, the Company had $110 million of borrowings outstanding on its Credit Facility and $145 million principal value of its Senior Notes, for a combined principal value of debt of $255 million. Interest expense, net was $8 million.
The Company paid a cash dividend of $0.40 per share, for a total of $8 million.
YEAR ENDED 2025 FINANCIAL RESULTS
Revenues totaled $392 million, net cash provided by operating activities was $213 million and net income was $161 million, or $7.59 per diluted share.
On a non-GAAP basis, Adjusted EBITDAX(1) was $261 million, cash flow from operations before changes in working capital(1) was $192 million, Total Free Cash Flow(1) was $81 million and Adjusted Net Income(1) was $96 million or $4.53 per diluted share.
Average realized prices, before derivative settlements, were $62.95 per barrel of oil, $(0.28) per Mcf of natural gas and $(1.27) per barrel of natural gas liquids. The Company reported a $36 million gain on derivatives, net, which included a $17 million realized gain on settlements.
Operating expenses included LOE of $88 million, or $8.21 per Boe, administrative costs of $31 million, or $2.95 per Boe, and production and ad valorem taxes of $29 million or $2.73 per Boe.
The Company incurred $120 million in total accrued capital expenditures ($83 million for upstream). On a cash basis, the Company had total capital expenditures of $128 million ($91 million for upstream).
The Company reduced total debt by $25 million, including a principal reduction of $5 million on the Credit Facility and $20 million on the Senior Notes. Interest expense, net was $31 million.
The Company paid dividends of $1.54 per share for a total of $33 million.
Shareholder's equity was $634 million as of December 31, 2025, an increase of 24% year-over-year and the number of common shares outstanding was 21.7 million, an increase of 1% year-over-year.
In January 2026, as part of our stock repurchase program, the Company repurchased 152,408 shares of common stock at a weighted average price of $26.54 per share for a total of $4 million.
RESERVES
Estimates of Riley Permian's proved reserves as of December 31, 2025, were prepared by Ryder Scott Company, L.P., the Company's third-party reservoir engineer, using the SEC pricing methodology. Proved reserves at year-end 2025 of 147 MMBoe increased by 24 MMBoe or 19% over year-end 2024 reserves. Oil represented 50% of total proved reserves. Proved developed producing reserves ("PDP") increased by 13% to 87 MMBoe, which represented 59% of total proved reserves. Proved undeveloped reserves ("PUD") increased by 29% to 61 MMBoe, when compared to year-end 2024. At December 31, 2025, the standardized measure of discounted cash flows and PV-10(1) were $1.14 billion and $1.39 billion, respectively.
The net proved reserve additions resulted in a reserve replacement ratio (defined as the sum of extensions and discoveries, revisions, acquisitions and divestitures, divided by annual production) of 323% for the year ended December 31, 2025. The organic reserve replacement ratio (defined as the sum of extensions and discoveries and revisions, divided by annual production) was 230%.
Extensions and discoveries were the primary contributor to the increase in reserves of 24 MMBoe, which consisted of 23 MMBoe added to PUDs as a result of drilling activity during the year, which allowed for the booking of adjacent PUDs for locations that were previously booked as unproved reserves or not at all, and 1 MMBoe added to PDP as a result of drilling successful wells that were previously classified as unproved locations. The Company also acquired 11 MMBoe in reserves and divested 1 MMBoe. The Company had production of 11 MMBoe and positive revisions of previous estimates of 1 MMBoe.
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(1)
A non-GAAP financial measure as defined and reconciled in the supplemental financial tables available on the Company's website at www.rileypermian.com.
Selected Operating and Financial Data
(Unaudited)
Three Months Ended
Year Ended
December 31, 2025
September 30, 2025
December 31, 2024
December 31, 2025
December 31, 2024
Select Financial Data (in thousands):
Oil and natural gas sales, net
$ 97,277
$ 106,852
$ 102,695
$ 391,980
$ 409,801
Income from Operations
$ 26,161
$ 28,862
$ 32,038
$ 133,279
$ 153,695
Adjusted EBITDAX(1)
$ 66,051
$ 64,041
$ 69,074
$ 260,565
$ 284,225
Cash Flow from Operations
$ 64,868
$ 63,650
$ 66,378
$ 212,539
$ 246,274
Upstream Accrual Capital Expenditures
$ 28,204
$ 13,129
$ 19,385
$ 82,785
$ 97,023
Upstream Cash Capital Expenditures
$ 34,721
$ 14,893
$ 22,299
$ 91,188
$ 99,365
Total Accrual Capital Expenditures
$ 50,357
$ 18,019
$ 30,682
$ 120,162
$ 108,320
Total Cash Capital Expenditures
$ 50,960
$ 29,027
$ 33,263
$ 127,855
$ 110,329
Upstream Free Cash Flow(1)
$ 17,238
$ 39,441
$ 28,653
$ 117,236
$ 128,033
Total Free Cash Flow(1)
$ 999
$ 25,307
$ 17,689
$ 80,569
$ 117,069
Production Data, net:
Oil (MBbls)
1,850
1,690
1,464
6,328
5,519
Natural gas (MMcf)
3,848
3,380
2,305
11,669
7,484
NGLs (MBbls)
778
722
455
2,387
1,486
Total (MBoe)
3,269
2,975
2,303
10,660
8,252
Daily combined volumes (Boe/d)
35,533
32,337
25,033
29,205
22,546
Daily oil volumes (Bbls/d)
20,109
18,370
15,913
17,337
15,079
Average Realized Prices:(2)
Oil ($ per Bbl)
$ 57.18
$ 63.94
$ 68.50
$ 62.95
$ 74.10
Natural gas ($ per Mcf)
$ (0.86)
$ (0.21)
$ 0.02
$ (0.28)
$ (0.19)
NGLs ($ per Bbl)
$ (6.67)
$ (0.66)
$ 5.18
$ (1.27)
$ 1.53
Average Realized Prices, including derivative settlements:(2)(3)
Oil ($ per Bbl)
$ 61.06
$ 65.17
$ 69.89
$ 65.46
$ 73.67
Natural gas ($ per Mcf)
$ (0.63)
$ (0.16)
$ 0.34
$ (0.22)
$ 0.37
NGLs ($ per Bbl)(4)
$ (6.67)
$ (0.66)
$ 5.18
$ (1.27)
$ 1.53
Weighted Average Common Shares Outstanding (in thousands):
Basic
21,120
21,164
21,094
21,134
20,712
Diluted
21,242
21,263
21,205
21,194
20,875
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(1)
A non-GAAP financial measure as defined and reconciled in the supplemental financial tables available on the Company's website at www.rileypermian.com.
(2)
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.
(3)
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.
(4)
During the periods presented, the Company did not have any NGL derivative contracts in place.
2026 GUIDANCE
Riley Permian is providing first quarter detailed guidance and select full-year 2026 activity guidance based on currently scheduled development activity and current market conditions. The average working interest on gross operated wells drilled is subject to change and may have corresponding impacts on net production volumes and investing expenditures. Total equivalent production estimates, inclusive of production from natural gas and NGLs, may be subject to variability based on third-party midstream service provider conditions.
Activity and Production
Q1 2026
Full-Year 2026
Net Operated Well Activity
Drilled (#)
14.3 - 16.3
37.0 - 43.0
Completed (#)
8.0 - 9.0
41.0 - 47.0
Turned to Sales (#)
