Riley Exploration Permian, Inc.: Q1 FY2026 earnings call

What management said about Q1 FY2026, from the documents filed with the SEC on 6 May 2026: press release. Guidance figures: 9 raised, 1 narrowed, 11 new, 4 kept. The quarter’s numbers.

Key takeaways

Production rose to 35.6 MBoe/d: Total equivalent production averaged 35.6 MBoe/d, oil 20.2 MBbls/d, against 24.4 MBoe/d a year earlier and 35.5 MBoe/d in the fourth quarter of 2025. Source
Derivative losses of $127 million: Net loss on derivatives was $127 million, including a $12 million realized settlement loss and a $115 million non-cash loss; management said the non-cash loss will be partly or fully offset by higher production revenue. Source
Full-year production guidance raised: Full-year 2026 total production guidance is 37.5 - 39.5 MBoe/d, up from 35.0 - 37.0 MBoe/d, and oil guidance is 22.0 - 23.0 MBbls/d, up from 21.0 - 22.0. Source
Full-year capital guidance raised: Full-year 2026 total capital expenditures guidance is $200 - $220 million, up from $190 - $210 million, with upstream at $175 - $190 million. Source
Gas hit by Waha pricing: Realized gas prices before GP&T costs were held down by Waha pricing and wider differentials to Henry Hub, despite higher Henry Hub benchmarks; net realized gas was $(1.68) per Mcf. Source
Operating and free cash flow: Operating cash flow was $47 million, or $55 million before working capital changes, and Total Free Cash Flow was $24 million. Source
Debt reduced by $8 million: Total debt principal fell to $247 million, with $107 million on the Credit Facility and $140 million of Senior Notes; debt-to-Adjusted EBITDAX was 1.0x at quarter end. Source

“with production exceeding guidance and capital spending below expectations”
Bobby Riley, Chief Executive Officer and Chairman of the Board

Guidance

Area	Period	Figure	Against last quarter
Net production, total equivalent Source	Full-year 2026	37.5 - 39.5	Raised from 35.0 - 37.0
Net production, oil Source	Full-year 2026	22.0 - 23.0	Raised from 21.0 - 22.0
Net production, total equivalent Source	Q2 2026	35.0 - 37.0	New
Net production, oil Source	Q2 2026	20.7 - 21.3	New
Net operated wells drilled Source	Full-year 2026	42.0 - 48.0	Raised from 37.0 - 43.0
Net operated wells drilled Source	Q2 2026	18.0 - 20.0	New
Net operated wells completed Source	Full-year 2026	43.0 - 49.0	Raised from 41.0 - 47.0
Net operated wells completed Source	Q2 2026	16.0 - 18.0	New
Net operated wells turned to sales Source	Full-year 2026	44.0 - 50.0	Raised from 43.0 - 49.0
Net operated wells turned to sales Source	Q2 2026	22.0 - 24.0	New
Non-operated wells, net Source	Full-year 2026	2.4 - 3.0	Raised from 1.0 - 2.0
Non-operated wells, net Source	Q2 2026	1.4 - 1.8	New
Upstream capital expenditures Source	Full-year 2026	$175 - $190	Raised from $165 - $180
Infrastructure and other capital expenditures Source	Full-year 2026	$25 - $30	Kept
Total capital expenditures Source	Full-year 2026	$200 - $220	Raised from $190 - $210
Upstream capital expenditures Source	Q2 2026	$65 - $75	New
Infrastructure and other capital expenditures Source	Q2 2026	$10 - $15	New
Total capital expenditures Source	Q2 2026	$75 - $90	New
Power joint venture investment Source	Full-year 2026	$7 - $8	Narrowed, low end up from $6 - $8
Power joint venture investment Source	Q2 2026	$2 - $3	New
Total investments Source	Full-year 2026	$207 - $228	Raised from $196 - $218
Total investments Source	Q2 2026	$77 - $93	New
Lease operating expense per Boe Source	Q2 2026	$8.00 - $9.00	Kept
Production and ad valorem taxes, % of revenue Source	Q2 2026	7.5% - 8.5%	Kept
Administrative costs per Boe Source	Q2 2026	$2.50 - $3.00	Kept

What changed from last quarter

Guidance raised: Full-year 2026 total equivalent production guidance raised to 37.5 - 39.5 MBoe/d from 35.0 - 37.0 MBoe/d. Source
Guidance raised: Full-year 2026 total capital expenditures guidance raised to $200 - $220 million from $190 - $210 million. Source
Guidance raised: Full-year 2026 net operated well activity guidance raised, with non-operated net wells raised to 2.4 - 3.0 from 1.0 - 2.0. Source
New guidance: Second-quarter 2026 detailed guidance provided, with updated full-year 2026 activity guidance. Source
Guidance kept: Second-quarter 2026 lease operating expense, production tax and administrative cost ranges match the first-quarter ranges in the prior release. Source

Production and earnings

Production rose to 35.6 MBoe/d: Total equivalent production averaged 35.6 MBoe/d, oil 20.2 MBbls/d, against 24.4 MBoe/d a year earlier and 35.5 MBoe/d in the fourth quarter of 2025. Source
Net loss against prior-year profit: Net loss was $70 million, or $(3.38) per diluted share, against net income of $29 million in the first quarter of 2025. Source
Derivative losses of $127 million: Net loss on derivatives was $127 million, including a $12 million realized settlement loss and a $115 million non-cash loss; management said the non-cash loss will be partly or fully offset by higher production revenue. Source
Adjusted EBITDAX of $61 million: Adjusted EBITDAX was $61 million, against $66 million in the fourth quarter of 2025 and $71 million in the first quarter of 2025. Source
Sales and operating income: Oil and natural gas sales were $114 million and income from operations was $44 million, against $102 million of sales and $50 million of operating income a year earlier. Source

Guidance and activity plan

Full-year production guidance raised: Full-year 2026 total production guidance is 37.5 - 39.5 MBoe/d, up from 35.0 - 37.0 MBoe/d, and oil guidance is 22.0 - 23.0 MBbls/d, up from 21.0 - 22.0. Source
Full-year capital guidance raised: Full-year 2026 total capital expenditures guidance is $200 - $220 million, up from $190 - $210 million, with upstream at $175 - $190 million. Source
Second-quarter oil range: Second-quarter oil production guidance is 20.7 - 21.3 MBbls/d, with total production guided at 35.0 - 37.0 MBoe/d. Source
Full-year well activity raised: Full-year net operated wells guidance is 42.0 - 48.0 drilled, 43.0 - 49.0 completed and 44.0 - 50.0 turned to sales, with non-operated net wells at 2.4 - 3.0. Source
Operating cost ranges unchanged: Second-quarter lease operating expense of $8.00 - $9.00 per Boe, production taxes of 7.5% - 8.5% of revenue and administrative costs of $2.50 - $3.00 per Boe match the prior ranges. Source

“Gas and NGL realizations were negatively impacted by regional gas egress constraints, which tempered cash flow results.”
Bobby Riley, Chief Executive Officer and Chairman of the Board

Realized prices and gas egress

Oil realization above fourth quarter: Oil realized $68.89 per barrel before derivatives, against $57.18 in the fourth quarter of 2025 and $70.12 in the first quarter of 2025. Source
Gas hit by Waha pricing: Realized gas prices before GP&T costs were held down by Waha pricing and wider differentials to Henry Hub, despite higher Henry Hub benchmarks; net realized gas was $(1.68) per Mcf. Source
NGL realizations pressured by allocation: NGL realized price was $(6.22) per barrel, as a larger share of GP&T costs was allocated to NGLs after lower realized gas revenues. Source

Operating costs per Boe

Lease operating expense per Boe: Lease operating expense was $24 million, or $7.51 per Boe, against $7.16 per Boe in the fourth quarter of 2025. Source
Administrative and tax costs per Boe: Administrative costs were $8 million, or $2.53 per Boe, and production and ad valorem taxes were $9 million, or $2.82 per Boe. Source
Total costs higher than prior year: Lease operating expenses were $24.1 million against $18.3 million a year earlier, and total costs and expenses were $70.2 million against $53.0 million. Source

“we remain confident in our outlook for meaningful year-over-year production growth and value creation throughout 2026.”
Bobby Riley, Chief Executive Officer and Chairman of the Board

Operated drilling by state

Operated wells drilled by state: 17 gross operated wells were drilled (15.6 net), 13 in Texas and 4 in New Mexico. Source
Texas accounted for sales turn-ins: 13 wells were completed and 8 turned to sales, all in Texas; New Mexico had no completions or turn-to-sales in the quarter. Source
New Mexico output rose: New Mexico produced 15.1 MBoe/d, against 7.3 MBoe/d a year earlier, and Texas produced 20.5 MBoe/d, against 17.1 MBoe/d. Source

Derivative and hedge positions

Oil hedges run into 2028: Second-quarter 2026 WTI swaps total 950,000 Bbl; WTI swap and collar volumes are listed through 2028 as of May 4, 2026. Source
Waha basis swaps below zero: Waha basis swaps are priced at $(2.26) per MMBtu for the second and third quarters of 2026 and $(0.94) to $(0.95) per MMBtu through 2027. Source
Interest rate position through April 2027: A $45 million long interest rate position at a 3.90% fixed rate covers May 2026 to April 2027. Source

Capital spending and cash flow

Accrual and cash capital spending: Capital expenditures before acquisitions were $47 million accrued and $31 million in cash; the fourth quarter of 2025 had $50 million accrued and $51 million in cash. Source
Operating and free cash flow: Operating cash flow was $47 million, or $55 million before working capital changes, and Total Free Cash Flow was $24 million. Source
Power joint venture investment: The company invested $4 million in RPC Power, its power-focused joint venture. Source
Current liabilities rose on derivatives: Current derivative liabilities rose to $77.9 million from less than $0.1 million at December 31, 2025, and accounts payable rose to $22.7 million from $5.1 million. Source

Debt and shareholder returns

Debt reduced by $8 million: Total debt principal fell to $247 million, with $107 million on the Credit Facility and $140 million of Senior Notes; debt-to-Adjusted EBITDAX was 1.0x at quarter end. Source
Dividend and share repurchases: Dividends were $0.40 per share, or $8 million, and 152 thousand shares were repurchased for $4 million at $26.54 per share. Source
Interest expense and share count: Interest expense, net was $6 million, and weighted average basic and diluted shares were 20.9 million. Source

Coming up, as management said on 6 May 2026

Updated presentation before call: An updated company presentation will be posted on the company website before the call, covering items to be discussed. Source

Figures management reported

Figure	Reported
Total equivalent production Source	35.6 MBoe/d
Oil production Source	20.2 MBbls/d
Realized oil price, before derivatives Source	$68.89 per Bbl
Realized natural gas price, before derivatives Source	$(1.68) per Mcf
Realized NGL price, before derivatives Source	$(6.22) per Bbl
Accrual capital expenditures before acquisitions Source	$47 million
Cash capital expenditures before acquisitions Source	$31 million
Lease operating expense per Boe Source	$7.51 per Boe
Administrative costs per Boe Source	$2.53 per Boe
Production and ad valorem taxes per Boe Source	$2.82 per Boe
Cash dividend per share Source	$0.40 per share
Shares repurchased Source	152 thousand shares for $4 million

Risks management discussed

Operational: Management said regional gas egress constraints lowered gas and NGL realizations and tempered cash flow results in the quarter. Source
Operational: Management said the average working interest on operated wells drilled may change, with effects on net production volumes and investing expenditures. Source
External: Realized NGL prices before GP&T costs declined in the quarter, which the company attributed mainly to lower Mont Belvieu pricing. Source

Earlier plans management reported on

Ahead: Management said production exceeded the first-quarter 2026 guidance range given in the prior release. Source
Not stated: Management said capital spending was below expectations; the accrual total was $47 million against the prior total capital guidance of $55 - $65 million. Source
Not stated: Management said it remains confident in production growth and value creation through 2026. Source

Other quarters

Summarised with AI from the documents the company filed with the SEC. Every point is checked against the filing before it is shown: management’s own words word for word, figures against the line or table row they come from. A point that fails the check is left out. Source opens the filing at that line.

As filed with the SEC

Open the filing on EDGAR

Riley Permian Reports First Quarter 2026 Results

OKLAHOMA CITY, May 6, 2026 -- Riley Exploration Permian, Inc. (NYSE American: REPX) (“Riley Permian” or the “Company”), today reported financial and operating results for the first quarter ended March 31, 2026.

FIRST QUARTER 2026 HIGHLIGHTS

Reported 35.6 MBoe/d of total equivalent production (oil production of 20.2 MBbls/d)
Generated $47 million of operating cash flow or $55 million before changes in working capitaland $24 million of Total Free Cash Flow
Incurred total accrual (activity-based) capital expenditures before acquisitions of $47 million and cash capital expenditures before acquisitions of $31 million
Reduced debt by $8 million with a quarter-end debt-to-Adjusted EBITDAX ratio of 1.0x
Repurchased 152 thousand shares of stock for $4 million

Bobby Riley, Chief Executive Officer and Chairman of the Board commented, “Our first quarter results reflect strong operational execution, with production exceeding guidance and capital spending below expectations. Gas and NGL realizations were negatively impacted by regional gas egress constraints, which tempered cash flow results. Despite these regional pricing pressures, the broader operating environment remains constructive, and we remain confident in our outlook for meaningful year-over-year production growth and value creation throughout 2026.”

(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 based on principal debt outstanding as of March 31, 2026, divided by Last Twelve Months Adjusted EBITDAX.

OPERATIONS AND DEVELOPMENT ACTIVITY UPDATE

The tables below provide a summary of our operated well activity and production by state:

	Three Months Ended March 31, 2026
	Gross		Net
Wells Drilled
Texas	13		12.5
New Mexico	4		3.1
Total	17		15.6
Wells Completed
Texas	13		12.8
New Mexico	-		-
Total		13		12.8
Wells Turned to Sales
Texas	8		8.0
New Mexico	-		-
Total	8		8.0

(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 March 31,
	2026	2025
Total Equivalent Production (MBoe/d)
Texas	20.5	17.1
New Mexico	15.1	7.3
Total	35.6	24.4
Oil Production (MBbls/d)
Texas	12.8	12.0
New Mexico	7.4	3.6
Total	20.2	15.6

FIRST QUARTER 2026 FINANCIAL RESULTS

Revenues totaled $114 million, operating income was $44 million, operating cash flow was $47 million and net loss was $70 million, or $(3.38) per diluted share.

On a non-GAAP basis, Adjusted EBITDAX was $61 million, cash flow from operations before changes in working capital was $55 million, Total Free Cash Flowwas $24 million and Adjusted Net Income was $21 million, or $1.02 per diluted share.

Average realized prices, before derivative settlements, were $68.89 per barrel of oil, $(1.68) per Mcf of natural gas and $(6.22) per barrel of natural gas liquids (“NGL”).

Realized natural gas prices before gathering, processing and transportation costs (“GP&T costs”) were negatively impacted by Waha pricing and wider differentials to Henry Hub driven by ongoing regional pipeline constraints, despite higher benchmark Henry Hub prices. Realized NGL prices before GP&T costs declined primarily due to lower Mont Belvieu pricing during the

(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.

quarter. NGL sales were further pressured by cost allocation effects, as lower realized natural gas revenues resulted in a greater proportion of GP&T costs being allocated to NGLs than in typical periods.

The Company reported a $12 million realized loss on derivative settlements, reflecting cash settlements on financial contracts linked to crude oil prices, and a $115 million non-cash loss due to the changes in the fair value of derivatives that will settle in future periods for a combined $127 million net loss on derivatives. Unrealized derivatives reflect the accounting remeasurement of the Company’s derivative portfolio based on changes in the market value of contracts that remain open and do not represent current-period cash inflows or outflows. In addition, unrealized derivatives will either be partially offset or entirely offset by the increased revenues from corresponding production over the same contract period.

Operating expenses included lease operating expense of $24 million, or $7.51 per Boe, administrative costs of $8 million, or $2.53 per Boe and production and ad valorem taxes of $9 million or $2.82 per Boe.

The Company incurred $47 million in total accrued capital expenditures. On a cash basis, the Company had total capital expenditures of $31 million. The Company invested $4 million in its power-focused joint venture, RPC Power.

The Company reduced total debt by $8 million, including a $3 million reduction on the Credit Facility and $5 million reduction on the Senior Notes. As of March 31, 2026, the Company had $107 million of borrowings outstanding on its Credit Facility and $140 million principal value of its Senior Notes, for a combined principal value of debt of $247 million. Interest expense, net was $6 million.

In January 2026, as part of our stock repurchase program, the Company repurchased 152 thousand shares of common stock at a weighted average price of $26.54 per share for a total of $4 million. The weighted average shares outstanding (basic and diluted) during the quarter was 20.9 million.

The Company paid a cash dividend of $0.40 per share, for a total of $8 million.

	Three Months Ended
	March 31, 2026		December 31, 2025		March 31, 2025
Selected Operating and Financial Data
(Unaudited)
Selected Financial Data (in thousands):
Oil and natural gas sales, net	$113,881		$97,277		$102,457
Income from operations	$43,670		$26,161		$49,502
Adjusted EBITDAX	$60,933		$66,051		$71,133
Cash flow from operations	$47,176		$64,868		$50,381
Upstream accrual capital expenditures	$47,087		$28,204		$19,434
Upstream cash capital expenditures	$30,130		$34,721		$16,274
Total accrual capital expenditures	$47,087		$50,357		$24,000
Total cash capital expenditures	$31,184		$50,960		$19,153
Upstream Free Cash Flow	$24,554		$17,238		$39,307
Total Free Cash Flow	$23,500		$999		$36,428
Production Data, net:
Oil (MBbls)		1,814		1,850		1,406
Natural gas (MMcf)		3,781		3,848		2,228
NGLs (MBbls)		760		778		422
Total equivalent (MBoe)	3,204		3,269		2,199
Daily equivalent production (Boe/d)		35,600		35,533		24,433
Daily oil production (Bbls/d)		20,156		20,109		15,622
Average Realized Prices:
Oil ($ per Bbl)	$68.89		$57.18		$70.12
Natural gas ($ per Mcf)	$(1.68)		$(0.86)		$0.71
NGLs ($ per Bbl)	$(6.22)		$(6.67)		$5.41
Average Realized Prices, including the effects of derivative settlements:(2)(3)
Oil ($ per Bbl)	$62.40		$61.06		$70.97
Natural gas ($ per Mcf)	$(1.67)		$(0.63)		$0.68
NGLs ($ per Bbl)	$(6.22)		$(6.67)		$5.41
Weighted Average Common Shares Outstanding (in thousands):
Basic	20,869		21,120		21,111
Diluted	20,869		21,242		21,111

(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 gathering, processing and transportation costs. These costs, related to natural gas and NGLs, at times exceeded the price received and resulted in negative average realized prices.

(3)The Company's calculation of the effects of derivative settlements includes gains (losses) on the settlement of our commodity derivative contracts. These realized gains (losses), along with unrealized gains (losses) from changes in the fair value of derivatives, are included under other expense on the Company’s condensed 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 second quarter detailed guidance and updated 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.

Activity and Production	Q2 2026	Full-Year 2026
Net Operated Well Activity
Drilled (#)	18.0 - 20.0	42.0 - 48.0
Completed (#)	16.0 - 18.0	43.0 - 49.0
Turned to Sales (#)	22.0 - 24.0	44.0 - 50.0
Non-Operated, Net (#)	1.4 - 1.8	2.4 - 3.0
Net Production
Oil (MBbls/d)	20.7 - 21.3	22.0 - 23.0
Total Equivalent (MBoe/d)	35.0 - 37.0	37.5 - 39.5
Capital Expenditures and Investments (in millions)
Upstream	$65 - $75	$175 - $190
Infrastructure and Other	$10 - $15	$25 - $30
Total Capital Expenditures	$75 - $90	$200 - $220
Power JV Investment	$2 - $3	$7 - $8
Total Investments	$77 - $93	$207 - $228

Operating and Corporate Costs	Q2 2026
Lease Operating Expenses ($ per Boe)	$8.00 - $9.00
Production and Ad Valorem Taxes (% of Revenue)	7.5% - 8.5%
Administrative Costs ($ per Boe)	$2.50 - $3.00

(1)Accrual (activity-based) investing expenditures before acquisitions

CONFERENCE CALL In connection with the earnings release, Riley Permian management will host a conference call for investors and analysts on May 7, 2026 at 9:00 a.m. CT to discuss the Company's results and to host a Q&A session. Interested parties are invited to participate by calling:

Toll Free Dial-In, +1 (888) 596-4144
Toll Dial-in, +1 (646) 968-2525
Conference ID number 1303008

An updated company presentation, which will include certain items to be discussed on the call, will be posted prior to the call on the Company's website (www.rileypermian.com).

A replay of the call will be available until May 21, 2026 by calling:

Toll Free Dial-In, +1 (800) 770-2030
Toll Dial-in, +1 (609) 800-9909
Conference ID number 1303008

About Riley Exploration Permian, Inc. Riley Permian is a growth-oriented upstream oil and gas company operating in Texas and New Mexico with infrastructure projects that complement our operations. For more information, please visit www.rileypermian.com.

Cautionary Statement Regarding Forward Looking Information and Guidance

Forward-looking statements notice

This press release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. The statements contained in this release that are not historical facts are forward-looking statements that represent management’s beliefs and assumptions based on currently available information. Forward-looking statements include information concerning our possible or assumed future results of operations, business strategies, need for financing, competitive position and potential growth opportunities. Our forward-looking statements do not consider the effects of future legislation or regulations. Forward-looking statements include all statements that are not historical facts and can be identified by the use of forward-looking terminology such as the words “believes,” “intends,” “may,” “should,” “anticipates,” “expects,” “could,” “plans,” “estimates,” “projects,” “targets,” “forecasts” or comparable terminology or by discussions of strategy or trends. You should not place undue reliance on these forward-looking statements. These forward-looking statements are subject to a number of risks, uncertainties and assumptions. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this release are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those anticipated or implied by the forward-looking statements.

Among the factors that could cause actual future results to differ materially are the risks and uncertainties the Company is exposed to. While it is not possible to identify all factors, we continue to face many risks and uncertainties including, but not limited to: the volatility of oil, natural gas and NGL prices, including basis differentials between published indices and the prices we actually receive for our production; regional supply and demand factors, any delays, curtailment delays or interruptions of production, and any governmental order, rule or regulation that may impose production limits; cost and availability of gathering, pipeline, refining, transportation, power and other midstream and downstream activities, which could result in a prolonged shut-in of our wells that may adversely affect our reserves, financial condition and results of operations; severe weather and other risks that lead to a lack of any available markets; our ability to successfully complete mergers, acquisitions or divestitures; the inability or failure of the Company to successfully integrate the acquired assets into our operations and development activities; the potential delays in the development, construction or start-up of planned projects; failure to realize any of the anticipated benefits of our joint ventures or other equity investments; risks relating to our operations, including development drilling and testing results and performance of acquired properties and newly drilled wells; inability to prove up undeveloped acreage and maintain production on leases; any reduction in our borrowing base on our Credit Facility from time to time and our ability to repay any excess borrowings as a result of such reduction; the impact of our derivative strategy and the results of future settlement; our ability to comply with the financial covenants contained in our Credit Facility and Senior Notes; changes in general economic, business or industry conditions, including changes in inflation rates, interest rates and foreign currency exchange rates; conditions in the capital, financial and credit markets and our ability to obtain capital needed to fund our exploration and development on favorable terms or at all; the loss of certain tax deductions; risks associated with executing our business strategy, including any changes in our strategy; risks associated with concentration of operations in one major geographic area; legislative or regulatory changes, including initiatives related to hydraulic fracturing, regulation of greenhouse gases, water conservation, seismic activity, weatherization, or protection of certain species of wildlife, or of sensitive environmental areas; the ability to receive drilling and other permits or approvals and rights-of-way in a timely manner (or at all), which may be restricted by governmental regulation and legislation; restrictions on the use of water, including limits on the use of produced water and a moratorium on new produced water well permits recently imposed by the Railroad Commission of Texas in an effort to control induced seismicity in the Permian Basin; changes in government environmental policies and other environmental risks; the availability of drilling equipment and the timing of production; tax consequences of business transactions; public health crisis, such as pandemics and epidemics, and any related government policies and actions and the effects of such public health crises on the oil and natural gas industry, pricing and demand for oil and natural gas and supply chain logistics; general domestic and international economic, market and political conditions, including military conflicts, global economic growth, unpredictability of new tariffs, actions of OPEC+ countries and changes to the current political environment under the current administration; risks related to litigation; and cybersecurity threats, technology system failures and data security issues.

The estimates and guidance presented in this release are based on assumptions of current and future capital expenditure levels, prices for oil, natural gas and NGLs, available liquidity, indications of supply and demand for oil, well results, operating costs and the timing and completion of pending projects and acquisitions. The guidance provided in this release does not constitute any form of guarantee or assurance that the matters indicated will be achieved. While we believe these estimates and the assumptions on which they are based are reasonable as of the date on which they are made, they are inherently uncertain and are subject to, among other things, significant business, economic, operational, and regulatory risks, and uncertainties, some of which are not known as of the date of the statement. Guidance and estimates, and the assumptions on which they are based, are subject to material revision. Actual results may differ materially from estimates and guidance.

Please read the "Risk Factors" in our annual report on Form 10-K and our quarterly reports on Form 10-Q, which are incorporated herein. Additional factors that could cause results to differ materially from those described above can be found in Riley Permian’s Annual Report on Form 10-K for the year ended December 31, 2025 filed with the SEC and available from the Company’s website at www.rileypermian.com under the “Investor” tab, and in other documents the Company files with the SEC.

The forward-looking statements in this press release are made as of the date hereof and are based on information available at that time. The Company does not undertake, and expressly disclaims, any duty to update or revise our forward-looking statements based on new information, future events or otherwise.

	(Unaudited)
	March 31, 2026	December 31, 2025
	(In thousands, except share amounts)
RILEY EXPLORATION PERMIAN, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
Assets
Current Assets:
Cash	$15,809	$17,889
Accounts receivable, net	56,629	41,045
Prepaid expenses	2,710	7,763
Inventory	7,919	7,929
Current derivative assets	-	19,141
Total Current Assets	83,067	93,767
Oil and natural gas properties, net (successful efforts)	1,018,168	995,539
Other property and equipment, net	22,784	21,872
Non-current derivative assets	1,388	5,117
Equity method investment	39,820	36,188
Funds held in escrow	1,196	1,196
Other non-current assets, net	13,658	15,899
Total Assets	$1,180,081	$1,169,578
Liabilities and Shareholders' Equity
Current Liabilities:
Accounts payable	$22,716	$5,083
Accrued liabilities	44,377	37,690
Revenue payable	57,186	59,606
Current derivative liabilities	77,937	37
Current portion of long-term debt	20,000	20,000
Other current liabilities	41,439	34,089
Total Current Liabilities	263,655	156,505
Non-current derivative liabilities	14,587	112
Asset retirement obligations	59,426	59,977
Long-term debt	220,675	227,855
Deferred tax liabilities	62,811	86,119
Other non-current liabilities	5,487	4,768
Total Liabilities	626,641	535,336
Commitments and Contingencies
Shareholders' Equity:
Preferred stock, $0.0001 par value, 25,000,000 shares authorized; 0 shares issued	-	-
Common stock, $0.001 par value, 240,000,000 shares authorized; 21,567,428 and 21,718,800 shares issued at March 31, 2026 and December 31, 2025, respectively	22	22
Additional paid-in capital	304,900	306,660
Retained earnings	248,518	327,560
Total Shareholders' Equity	553,440	634,242
Total Liabilities and Shareholders' Equity	$1,180,081	$1,169,578

	Three Months Ended March 31,
	2026	2025
	(In thousands, except per share amounts)
RILEY EXPLORATION PERMIAN, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Revenues:
Oil and natural gas sales, net	$113,881	$102,457
Total Revenues	113,881	102,457
Costs and Expenses:
Lease operating expenses	24,071	18,331
Production and ad valorem taxes	9,032	6,670
Exploration costs	967	9
Depletion, depreciation, amortization and accretion	25,720	19,138
General and administrative:
Administrative costs	8,120	7,438
Stock-based compensation expense	2,301	1,369
Total Costs and Expenses	70,211	52,955
Income from Operations	43,670	49,502
Other Expense:
Interest expense, net	(6,357)	(6,661)
Loss on derivatives, net	(126,970)	(5,850)
Loss from equity method investment	(368)	(119)
Loss on acquisitions and divestitures, net	(2,697)	-
Total Other Expense	(136,392)	(12,630)
Net Income (Loss) from Operations before Income Taxes	(92,722)	36,872
Income tax benefit (expense)	22,288	(8,239)
Net Income (Loss)	$(70,434)	$28,633
Net Income (Loss) per Share:
Basic	$(3.38)	$1.36
Diluted	$(3.38)	$1.36
Weighted Average Common Shares Outstanding:
Basic	20,869	21,111
Diluted	20,869	21,111

	Three Months Ended March 31,
	2026	2025
	(In thousands)
RILEY EXPLORATION PERMIAN, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Cash Flows from Operating Activities:
Net income (loss)	$(70,434)	$28,633
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Exploratory well costs and lease expirations	913	9
Depletion, depreciation, amortization and accretion	25,720	19,138
Loss on derivatives, net	126,970	5,850
Settlements on derivative contracts	(11,725)	1,115
Amortization of deferred financing costs and discount	1,182	1,182
Stock-based compensation expense	2,301	1,369
Deferred income tax benefit	(23,308)	(1,826)
Loss from equity method investment	368	119
Loss on acquisitions and divestitures, net	2,697	-
Other	-	(8)
Changes in operating assets and liabilities	(7,508)	(5,200)
Net Cash Provided by Operating Activities	47,176	50,381
Cash Flows from Investing Activities:
Additions to oil and natural gas properties	(29,570)	(16,150)
Additions to midstream property and equipment	(1,054)	(2,879)
Additions to other property and equipment	(560)	(124)
Acquisitions of oil and natural gas properties	(2,175)	-
Acquisitions of land	(544)	-
Proceeds from divestitures	7,607	-
Contributions to equity method investment	(4,000)	(6,250)
Distributions from equity method investment	1,487	-
Net Cash Used in Investing Activities	(28,809)	(25,403)
Cash Flows from Financing Activities:
Deferred financing costs	(26)	(140)
Proceeds from Credit Facility	8,000	-
Repayments under Credit Facility	(11,000)	(16,000)
Repayments of Senior Notes	(5,000)	(5,000)
Payment of cash dividends	(8,360)	(8,033)
Repurchase of common shares	(4,048)	-
Repurchase of common shares for tax withholding and other	(13)	(72)
Net Cash Used in Financing Activities	(20,447)	(29,245)
Net Decrease in Cash	(2,080)	(4,267)
Cash, Beginning of Period	17,889	13,124
Cash, End of Period	$15,809	$8,857

DERIVATIVE INSTRUMENTS

The Company’s oil and natural gas derivative contracts consisted of fixed price swaps, costless collars and basis swaps. The following table summarizes the open financial derivatives as of May 4, 2026, related to our future oil and natural gas production:

	2026			2027				2028
	Second Quarter	Third Quarter	Fourth Quarter	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	First Quarter
Oil
WTI Oil Swaps
Volume (Bbl)	950,000	860,000	820,000	755,000	650,000	630,000	605,000	330,000
Weighted average price ($/Bbl)	$62.51	$61.65	$61.42	$61.79	$61.68	$61.38	$61.62	$70.18
WTI Oil Collars
Volume (Bbl)	541,000	570,000	550,000	475,000	537,000	400,000	225,000	180,000
Weighted average floor price ($/Bbl)	$58.84	$58.25	$57.75	$57.15	$55.84	$52.93	$56.33	$55.00
Weighted average ceiling price ($/Bbl)	$73.60	$72.66	$69.59	$66.42	$67.97	$65.87	$67.06	$73.33
Natural Gas
Henry Hub Natural Gas Swaps
Volume (MMBtu)	450,000	300,000	500,000	600,000
Weighted average price ($/MMBtu)	$3.64	$3.59	$4.07	$4.19
Henry Hub Natural Gas Collars
Volume (MMBtu)	900,000	900,000	600,000	450,000
Weighted average floor price ($/MMBtu)	$3.05	$3.05	$3.43	$3.80
Weighted average ceiling price ($/MMBtu)	$3.74	$3.74	$4.79	$5.84
Waha Basis Swaps
Volume (MMBtu)	450,000	450,000	600,000	3,150,000	3,150,000	3,150,000	3,150,000	1,800,000
Weighted average price ($/MMBtu)	$(2.26)	$(2.26)	$(1.31)	$(0.94)	$(0.95)	$(0.95)	$(0.95)	$(1.01)

(1)Q2 2026 derivative positions shown include 2026 contracts, some of which have settled as of May 4, 2026.

Interest Rate Contracts

The following table summarizes the open interest rate derivative positions as of May 4, 2026:

Open Coverage Period

Position

Notional Amount

Fixed Rate

(In thousands)

May 2026 - April 2027

Long

$45,000

3.90%

Contacts
Ben McQueen
405-438-0126
IR@rileypermian.com