NYSE: EPM

Recent Developments

Dividend Declaration

On September 10, 2026, Evolution’s Board of Directors approved and declared a quarterly dividend of $0.12 per common share payable September 30, 2026.

Purchase of Permian Minerals

On August 20, 2026, we completed the acquisition of mineral and royalty interests in the core Midland Basin of the Permian Basin from a non-affiliated private seller for a total purchase price of $16.0 million (the “Permian Minerals Acquisition”), subject to customary post-closing adjustments. The Permian Minerals Acquisition has an effective date of August 1, 2026. We funded the purchase price for the Permian Minerals Acquisition with a combination of net proceeds from our concurrent public equity offering and $3.2 million in borrowings under our Senior Secured Credit Facility. The acquired assets include approximately 3,420 net royalty acres across Reagan, Martin, Midland, Glasscock, and Upton Counties, Texas.

Common Stock Offering

On August 20, 2026, we completed a public offering of 4.3 million shares of our common stock, at an offering price of $3.25 per share (the “Offering”). We received net proceeds of approximately $12.8 million from the Offering, after deducting underwriting discounts and commissions and estimated offering expenses. Net proceeds from the Offering, together with borrowings under our Senior Secured Credit Facility and cash on hand, were used to fund the Permian Minerals Acquisition.

Senior Secured Credit Facility

On August 20, 2026, we entered into a letter agreement with MidFirst Bank pursuant to which the borrowing base on our Senior Secured Credit Facility was temporarily increased from $65.0 million to $73.0 million from August 20, 2026

until October 20, 2026, unless redetermined earlier in accordance with the credit agreement. We currently expect to begin our semi-annual Fall redetermination on or about October 1, 2026.

Previously on November 28, 2025, we entered into a letter agreement with MidFirst Bank pursuant to which the Margined Collateral Value, as defined under the Senior Secured Credit Facility, was modified to $65.0 million. In addition, it granted us additional time to enter into further commodity hedges to meet the hedging requirements under the Senior Secured Credit Facility.

Purchase of Louisiana Minerals

From December 2025 through June 2026, we acquired mineral and royalty interests in multiple parishes across Louisiana from various private sellers for cash consideration totaling $6.2 million, including capitalized direct transaction costs (“Louisiana Minerals”). The mineral acreage in Louisiana consists of proved producing wells, drilled but not yet producing wells, and undeveloped acreage targeting the Bossier/Haynesville Shales and is currently being actively developed by operators in the area. The acquisitions were considered asset acquisitions and funded with cash on hand and proceeds of sales under our ATM Sales Agreements.

SCOOP/STACK Transactions

On August 4, 2025, we completed the acquisition of certain mineral and royalty interests in the SCOOP and STACK plays in Oklahoma from a non-affiliated private seller (the “SCOOP/STACK Minerals Acquisition”) in a cash transaction valued at approximately $16.3 million, which includes $17.0 million paid at closing less transaction costs of $0.1 million and interim purchase price adjustments totaling approximately $0.8 million related to net cash flows earned on the properties from the effective date of May 1, 2025 to the closing date. We accounted for the transaction as an asset acquisition and the allocation of the purchase price was $12.5 million to proved oil and natural gas properties, subject to amortization, and $3.8 million to unproved properties. We funded the purchase price for the SCOOP/STACK Minerals Acquisition with a combination of $15.0 million in borrowings under our Senior Secured Credit Facility and cash on hand. The acquired assets include an average royalty interest of 0.6% across approximately 5,500 net royalty acres located primarily in Grady and Canadian Counties, Oklahoma.

On June 30, 2026, we completed the divestiture of a portion of our non-core, non-producing net mineral acres in the SCOOP/STACK with a private buyer. The divestiture included 3,700 net royalty acres for a total sale price of approximately $3.1 million, before customary post-closing adjustments.

At-the-Market (“ATM”) Equity Sales Program

On October 21, 2024, we entered into an ATM equity Sales Agreement with Roth Capital Partners, LLC (the “Lead Agent”), Northland Securities Inc., and A.G.P./Alliance Global Partners pursuant to which we may issue and sell, from time to time, up to $30.0 million of shares of common stock through or to the Lead Agent, acting as agent or principal to facilitate acquisitions and other general corporate purposes. On February 11, 2026, the Company executed a new ATM equity Sales Agreement, substantially consistent with the original October 2024 agreement (the “ATM Sales Agreements”) restoring the $30.0 million common stock sales capacity. For the year ended June 30, 2026, we sold a total of approximately 1.4 million shares of our common stock under the ATM Sales Agreements for net proceeds of approximately $5.8 million, net of $0.2 million of offering costs incurred. Net proceeds from the sales of common stock were used to fund a portion of our Louisiana Minerals acquisitions and for general corporate purposes.

Business Strategy

Our business strategy is to maximize total shareholder return through disciplined management and growth of our asset base, while being mindful of the current operating environment and marketplace. The key elements of our strategy to accomplish our goal of maximizing shareholder return are:

● Maintaining a strong balance sheet and conservative financial management;

● Growing the asset base through investment in our existing properties, direct acquisitions of oil and natural gas properties, including both working and mineral and royalty interests, selective development opportunities, or accretive acquisitions of similar companies; and

● Returning cash to shareholders by sustaining and growing our dividend payout over time or repurchases of our shares in the open market.

Properties

As of June 30, 2026, our oil and natural gas properties consist primarily of non-operated working interests and mineral and working interests in the following areas (as well as small overriding royalty and mineral interests in Texas):

SCOOP/STACK – Central Oklahoma

Our non-operated working and mineral interests in the SCOOP and STACK plays, consist of oil and natural gas producing properties in the Anadarko basin, where we hold an approximate 2.6% average net working interest with an associated 2.0% average net revenue interests located on approximately 101,100 gross (4,000 net) acres (all held by production) and a separate approximate 0.6% average net royalty interest located on approximately 8,600 gross (1,800 net) royalty acres across Blaine, Canadian, Carter, Custer, Dewey, Garvin, Grady, Kingfisher, McClain, Murray, and Stephens counties in Oklahoma. The oil and natural gas properties are primarily operated by Continental Resources, Inc., Ovintiv USA Inc., Validus Energy, and EOG Resources, Inc. with approximately 34% of wells operated by other operators.

For the year ended June 30, 2026, our average net daily production from the SCOOP/STACK properties was 1.4 MBOEPD consisting of 54% natural gas, 24% oil, and 22% NGLs. Hydrocarbons produced from our SCOOP/STACK properties are sold to various purchasers throughout the mid-continent.

Chaveroo Field – Chaves and Roosevelt Counties, New Mexico

Our non-operated working interests in the Chaveroo Field consist of a 50% net working interest, with an average associated 41% average revenue interest, in approximately 4,500 gross (2,300 net) acres all held by production, associated with six development blocks with the right to acquire the same working interest in additional development locations and associated acreage at a fixed price. The field is operated by PEDEVCO Corp. (“PEDEVCO”).

For the year ended June 30, 2026 our average net daily production from the Chaveroo Field properties was 0.3 MBOEPD consisting of 100% oil. Oil produced from our Chaveroo Field properties is sold to Phillips 66 in New Mexico.

Jonah Field – Sublette County, Wyoming

Our non-operated working interests in the Jonah Field, a natural gas and NGL property in Sublette County, Wyoming, consist of approximately 20% average net working interest and approximately 15% average net revenue interest located on approximately 5,300 gross (950 net) acres all held by production. The properties are operated by Jonah Energy (“Jonah”).

For the year ended June 30, 2026 our average net daily production from the Jonah Field properties was 1.4 MBOEPD consisting of 89% natural gas, 6% NGLs, and 5% oil. Hydrocarbons produced from our Jonah Field properties are sold to West Coast markets.

Williston Basin – Williston, North Dakota

Our non-operated working interests in the Williston Basin, oil and natural gas producing properties, consist of approximately 39% average net working interest and approximately 33% average net revenue interest located on approximately 133,800 gross (40,100 net) acres (approximately 99% held by production) across Billings, Golden Valley, and McKenzie Counties in North Dakota. The properties are operated by Foundation Energy Management (“Foundation”).

For the year ended June 30, 2026, our average net daily production from the Willison Basin properties was 0.4 MBOEPD consisting of 73% oil, 16% NGLs, and 11% natural gas. The primary producing reservoirs are the Three Forks, Pronghorn, and Bakken formations. Hydrocarbons produced from the Williston Basin properties are sold to local refineries and purchasers.

Barnett Shale – North Texas

Our non-operated working and overriding royalty interests in the Barnett Shale, a natural gas and NGL producing shale reservoir, consist of approximately 17% average net working interest and approximately 14% average net revenue interest (inclusive of the overriding royalty interests) located on approximately 123,800 gross (21,000 net) acres held by production across nine North Texas counties (Bosque, Denton, Erath, Hill, Hood, Johnson, Parker, Somervell, and Tarrant), in the Barnett Shale. The oil and natural gas properties are primarily operated by Diversified Energy Company, until sold to Eagleridge Operating, LLC in June 2026, with approximately 19% of wells operated by five other operators.

For the year ended June 30, 2026, our average net daily production from the Barnett Shale properties was 2.2 MBOEPD consisting of 73% natural gas, 26% NGLs, and 1% oil. The producing reservoir is the Barnett Shale, which is also the source rock. Hydrocarbons produced from our Barnett Shale properties are sold to Gulf Coast markets.

Hamilton Dome – Hot Springs County, Wyoming

Our non-operated working interests in the Hamilton Dome Field, a secondary recovery field utilizing water injection wells to pressurize the reservoir, consist of approximately 24% average net working interest, with an associated 20% average net revenue interest (inclusive of a small overriding royalty interest). The approximately 5,900 gross acre unitized field, of which we hold approximately 1,400 net acres, is operated by Merit Energy Company (“Merit”), a private oil and natural gas company, who owns the majority of the remaining working interest in the Hamilton Dome Field. The Hamilton Dome Field is located in the southwest region of the Big Horn Basin in northwest Wyoming.

For the year ended June 30, 2026, our average net daily production from the Hamilton Dome Field properties was 0.4 MBOEPD consisting of 100% oil. The primary producing reservoirs in the field are the Tensleep and Phosphoria. Produced oil from the field is subject to Western Canadian Select pricing.

Delhi Field – Enhanced Oil Recovery CO2 Flood – Onshore Louisiana

Our non-operated working and overriding royalty interests in the Delhi Field, a CO2-EOR project, consist of approximately 24% average net working interest, with an associated 19% average net revenue interest and separate overriding royalty and mineral interests of approximately 7% yielding a total average net revenue interest of approximately 26%. The field is operated by Denbury Onshore LLC (“Denbury”), a subsidiary of Exxon Mobil Corporation (“ExxonMobil”). The Delhi Field is comprised of approximately 13,600 gross unitized acres, of which we hold approximately 3,200 net acres, and is located in northeast Louisiana in Franklin, Madison, and Richland Parishes.

For the year ended June 30, 2026, our average net daily production from the Delhi Field properties was 0.6 MBOEPD consisting of 81% oil and 19% NGLs. The primary producing reservoirs in the field are the Tuscaloosa and Paluxy formations. Produced oil from the field is priced off of Louisiana Light Sweet (“LLS”) crude, which often trades at a premium to West Texas Intermediate (“WTI”).

Other – Haynesville/Bossier Shale and TexMex – Louisiana, Texas, and New Mexico

Our mineral and royalty interest in the Haynesville/Bossier Shale, consists of a mix of natural gas producing wells, drilled but not yet producing wells, and proved undeveloped acreage with an approximate average 0.3% net royalty interest. Our mineral and royalty interest span across an approximate 3,600 gross (465 net) acres located in Bossier, Caddo, DeSoto, Red River and Sabine parishes in Louisiana.

Our non-operated working interest in TexMex consists of oil and natural gas producing properties where we hold an approximate 42% net working interest and a 35% average net revenue interest located on approximately 27,800 gross (11,200 net) acres held by production located primarily in Lea, Eddy, and Chaves Counties, New Mexico and Stephens County, Texas. The oil and natural gas properties are operated by Texian Operating Company.

For the year ended June 30, 2026, our average net daily production from these other properties was 0.4 MBOEPD consisting of 50% oil, 48% natural gas, and 1% NGLs. Hydrocarbons produced from such other properties are sold to various purchasers throughout Texas, New Mexico and Louisiana.

Refer to “Production volumes, average sales price and average production costs” table below for further information regarding our properties and their fiscal year results.

Estimated Oil and Natural Gas Reserves and Estimated Future Net Revenues

The SEC sets rules related to reserve estimation and disclosure requirements for oil and natural gas companies. These rules require disclosure of oil and natural gas proved reserves by significant geographic area, using the trailing 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, rather than year-end prices, and allows the use of new technologies in the determination of proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. Subject to limited exceptions, the rules also require that proved undeveloped reserves may only be classified as such if a development plan has been adopted indicating that they are scheduled to be drilled within five years.

There are numerous uncertainties inherent in estimating quantities of proved reserves and estimates of reserves quantities and values must be viewed as being subject to significant change as more data about the properties becomes available.

Summary of Oil & Gas Reserves for Fiscal Year Ended 2026

Our proved reserves as of June 30, 2026, denominated in thousands of barrels of oil equivalent (“MBOE”), were estimated by our independent reservoir engineers, Cawley, Gillespie and Associates, Inc. (“CG&A”) and DeGolyer and MacNaughton (“D&M”), both worldwide petroleum consultants.

CG&A evaluated the reserves for our SCOOP/STACK, Chaveroo Field, Jonah Field, Williston Basin, TexMex, and Louisiana Minerals properties. The scope and results of their procedures are summarized in a letter from the firm, which is included as Exhibit 99.1 to this Annual Report on Form 10-K.

D&M evaluated the reserves for our Barnett Shale, Hamilton Dome, and Delhi Field properties. The scope and results of their procedures are summarized in a letter from the firm, which is included as Exhibit 99.2 to this Annual Report on Form 10-K.

The following table sets forth our estimated proved reserves as of June 30, 2026. For additional reserves information, see our Supplemental Disclosure about Oil and Natural Gas Properties (unaudited) to our consolidated financial statements in Item 8. Financial Statements and Supplementary Data. The New York Mercantile Exchange (“NYMEX”) previous 12-month unweighted arithmetic average first-day-of-the-month price used to calculate estimated revenues was $72.93 per barrel of oil and $3.62 per MMBtu of natural gas. The net price per barrel of NGLs was $27.50, which does not have any single comparable reference index price. The NGL price was based on historical differentials to WTI. For periods for which no historical price information was available, we used comparable pricing in the geographic area. Pricing differentials were applied for each individual property and product based on quality, processing, transportation, location and other pricing aspects.

Proved Reserves as of June 30, 2026

Total Proved

Percent of

Oil

Natural Gas

NGLs

Reserves

Total Proved

Reserve Category

​ ​ ​

(MBbls)

​ ​ ​

(MMcf)

​ ​ ​

(MBbls)

​ ​ ​

(MBOE)(1)

​ ​ ​

Reserves

Proved:

Developed Producing

7,049

67,400

3,750

22,032

80.9

%

Developed Non-Producing

1.3

%

Undeveloped

3,275

6,533

4,836

17.8

%

Total Proved

10,625

74,192

4,227

27,217

100.0

%

Product Mix

39.1%

45.4%

15.5%

100.0%

Total Proved by Property:

SCOOP/STACK

1,325

15,080

1,112

4,950

18.2

%

Chaveroo Field

2,714

3,047

11.2

%

Jonah Field

18,484

3,500

12.9

%

Williston Basin

1,674

1,337

2,229

8.2

%

Barnett Shale

29,366

1,738

6,705

24.6

%

Hamilton Dome Field

1,684

—

—

1,684

6.1

%

Delhi Field

1,658

—

2,278

8.4

%

TexMex and Other

1,316

9,048

—

2,824

10.4

%

Total Proved

10,625

74,192

4,227

27,217

100.0

%

(1) Equivalent oil reserves are defined as six Mcf of natural gas and 42 gallons of NGLs to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence. Natural gas prices per Mcf and NGL prices per barrel often differ significantly from the equivalent amount of oil.

Internal Controls Over Reserves Estimation Process and Qualifications of Technical Persons with Oversight for the Company’s Overall Reserve Estimation Process

Our policies regarding internal controls over reserves estimates require such estimates to be prepared by an independent petroleum engineering firm under the supervision of our internal reserve engineering team, which includes our Chief Operating Officer (“COO”), J. Mark Bunch. Our internal reserve engineering team has a combined experience of over 80 years in Petroleum Engineering. Our COO, the person responsible for overseeing the preparation of our reserves estimates, has a Bachelor of Science Degree in Petroleum Engineering from Texas A&M University, is a registered Professional Engineer in the State of Texas (No. 86704), has over 40 years of oil and natural gas experience including large independents and financial firm services for projects and acquisitions. Our Board of Directors also has oversight of our reserve estimation process and contains a Reserves Committee with William Dozier, an independent director who is a Registered Professional Engineer in the State of Texas (No. 47279) with experience in energy company reserve evaluations. Such reserve estimates comply with generally accepted petroleum engineering and evaluation principles, definitions, and guidelines as established by the SEC.

The reserves information in this filing is based on estimates prepared by CG&A and D&M. The person responsible for the preparation of the reserve report at CG&A is W. Todd Brooker, P.E., President. Mr. Brooker received a Bachelor of Science degree in Petroleum Engineering in 1989 from the University of Texas at Austin and is a registered Professional Engineer in the State of Texas (No. 83462). Mr. Brooker joined CG&A in 1992 and has over 30 years of experience in engineering and geological services. The person responsible for the preparation of the reserve report at D&M is Dr. Dilhan Ilk, P.E., Executive Vice President. Dr. Ilk received a Bachelor of Science degree in Petroleum Engineering in 2003 from Istanbul Technical University and a Master’s degree and Doctorate in Petroleum Engineering in 2005 and 2010, respectively, from Texas A&M University, and he has in excess of 16 years of experience in oil and natural gas reservoir studies and evaluations and is a licensed Professional Engineer in the state of Texas (No. 139334).

We provide CG&A and D&M with our property interests, production, current operating costs, current production prices, estimated abandonment costs and other information in order for them to prepare the reserve estimates. This information is reviewed by our senior management team and designated operations personnel to ensure accuracy and completeness of the data prior to submission to the reserve engineers. The scope and results of CG&A’s and D&M’s procedures, as

well as their professional qualifications, are summarized in the letters included as Exhibit 99.1 and Exhibit 99.2, respectively, to this Annual Report on Form 10-K.

Proved Undeveloped Reserves

During the year ended June 30, 2026 our proved undeveloped (“PUD”) reserves changed as follows:

Oil

Natural Gas

NGLs

Total Reserves

Proved undeveloped reserves:

​ ​ ​

(MBbls)

​ ​ ​

(MMcf)

​ ​ ​

(MBbls)

​ ​ ​

(MBOE)(1)

June 30, 2025

3,401

3,599

4,413

Revisions of previous estimates

(161)

(19)

(136)

Improved recovery, extensions and discoveries

Purchase of reserves in place

—

2,667

Transfers

(2)

(186)

(17)

(50)

June 30, 2026

3,275

6,533

4,836

(1) Equivalent oil reserves are defined as six Mcf of natural gas and 42 gallons of NGLs to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence. Natural gas prices per Mcf and NGL prices per barrel often differ significantly from the equivalent amount of oil.

Our PUD reserves were 4.8 MMBOE as of June 30, 2026, with related future development costs of approximately $74.8 million, primarily associated with the Chaveroo Field, Williston Basin, and SCOOP/STACK. We acquired 0.4 MMBOE primarily from our Louisiana Minerals acquisitions during fiscal 2026. Extensions of 0.2 MMBOE are primarily associated with new wells at SCOOP/STACK. Transfers of 0.1 MMBOE are associated with ten gross SCOOP/STACK wells drilled, completed and placed online during fiscal 2026. The net downward revisions were due primarily to adjustments made to the timing of the Williston Basin development plan resulting in the roll-off of PUDs expected to be developed beyond five years. Under SEC reporting requirements, our PUD reserves include only those reserves in which the Company has current plans to develop within five years. See “Drilling and Present Activities” below for a further discussion of our expected development of the PUDs associated with SCOOP/STACK, the Chaveroo Field, and Williston Basin.

Drilling and Present Activities

Currently, none of our oil and natural gas properties are operated by us. We therefore rely on information from our operators regarding near-term drilling programs. There are no plans to drill new wells in fiscal year 2027 in the Jonah Field, the Barnett Shale, Delhi Field, the Hamilton Dome Field or at TexMex. At this time, operators of all of our working interest properties are periodically running workover rigs focusing on projects to return wells to production that have experienced mechanical issues.

At SCOOP/STACK, we have received proposals for ten gross wells which we expect to be brought online during fiscal year 2027. Additionally, as our third-party operators continue to be active around our acreage, we would expect additional wells to be drilled and/or completed. At the Chaveroo Field, we have drilling permits in hand for the next round of six gross wells and are in discussions with our partner as to timing for spudding these wells.

At our Louisiana and Oklahoma minerals properties, there are currently 18 gross wells in progress. Additionally, as our third-party operators continue to be active around our acreage we expect additional wells to be drilled and/or completed throughout fiscal year 2027.

For further discussion, see “Capital Expenditures” within Item 7. Management’s Discussion and Analysis of Financial Conditions and Results of Operations.

Production volumes, average sales price and average production costs

The following table summarizes our crude oil, natural gas, and natural gas liquids production volumes, average sales price per unit and average daily production on an equivalent basis for the periods indicated:

Years Ended June 30,

​ ​ ​

Volume

​ ​ ​

Price

​ ​ ​

Volume

​ ​ ​

Price

​ ​ ​

Volume

​ ​ ​

Price

Production:

Crude oil (MBBL)

SCOOP/STACK

$

71.90

$

70.90

$

79.77

Chaveroo Field

66.26

63.49

77.90

Jonah Field

65.79

64.50

78.51

Williston Basin

67.14

63.56

73.97

Barnett Shale

67.80

65.65

75.01

Hamilton Dome Field

58.70

57.97

65.18

Delhi Field

67.15

72.33

79.46

TexMex and Other

71.17

64.27

78.79

Total

$

66.61

$

66.71

$

75.38

Natural gas (MMCF)

SCOOP/STACK

1,586

$

3.51

1,297

$

3.34

$

2.46

Chaveroo Field

—

—

—

—

2.17

Jonah Field

2,818

2.76

3,081

2.94

3,448

3.55

Williston Basin

2.62

2.38

1.72

Barnett Shale

3,532

2.97

3,855

2.51

4,165

1.87

TexMex and Other

2.41

2.63

—

—

Total

8,428

$

2.97

8,409

$

2.80

8,243

$

2.61

Natural gas liquids (MBBL)

SCOOP/STACK

$

21.98

$

23.16

$

23.16

Chaveroo Field

—

—

—

—

21.93

Jonah Field

26.06

29.32

28.67

Williston Basin

17.55

19.91

21.85

Barnett Shale

27.93

27.86

27.61

Delhi Field

28.85

30.08

27.91

TexMex and Other

20.37

—

—

—

—

Total

$

25.65

$

27.11

$

27.13

Equivalent (MBOE)(1)

SCOOP/STACK

$

33.52

$

37.64

$

40.43

Chaveroo Field

66.26

63.49

72.10

Jonah Field

19.63

20.61

24.76

Williston Basin

53.51

52.43

63.10

Barnett Shale

20.96

18.74

15.93

Hamilton Dome Field

58.70

57.97

65.18

Delhi Field

59.81

62.56

68.03

TexMex and Other(2)

43.35

44.63

78.79

Total

2,583

$

33.43

2,582

$

33.25

2,485

$

34.56

Average daily production (BOEPD)(1)

SCOOP/STACK

1,351

1,175

Chaveroo Field

Jonah Field

1,447

1,578

1,768

Williston Basin

Barnett Shale

2,203

2,375

2,557

Hamilton Dome Field

Delhi Field

TexMex and Other(2)

Total

7,077

7,074

6,790

(1) Equivalent oil reserves are defined as six Mcf of natural gas and 42 gallons of NGLs to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence. Natural gas prices per Mcf and NGL prices per barrel often differ significantly from the equivalent amount of oil. Average daily production presented in the table above represents our fiscal year production divided by 365 days in the year for fiscal years 2026 and 2025. Average daily production presented in the table above represents our fiscal year production divided by 366 days in the year for fiscal year 2024.

(2) At TexMex, our average daily production since TexMex’s acquisition date of April 14, 2025 through June 30, 2025, was 0.4 MBOEPD.

The following table summarizes our production costs, and production costs per unit for the periods indicated:

Years Ended June 30,

Production costs (in thousands, except per BOE)

Total lease operating costs(1)

Amount

per BOE

Amount

per BOE

Amount

per BOE

SCOOP/STACK

$

4,423

$

8.97

$

4,442

$

10.35

$

1,647

$

8.71

Chaveroo Field

1,307

13.76

13.58

15.40

Jonah Field

7,822

14.84

8,470

14.73

9,101

14.09

Williston Basin

4,886

29.98

5,063

29.61

5,235

29.08

Barnett Shale(2)

14,021

17.44

13,217

15.25

14,695

15.68

Hamilton Dome Field

5,088

38.13

5,479

39.61

5,722

40.37

Delhi Field

6,972

29.72

10,604

34.59

11,390

31.76

TexMex and Other

5,819

43.81

1,194

38.84

9.10

Total

$

50,338

$

19.48

$

49,338

$

19.11

$

48,273

$

19.43

(1) Total lease operating costs include lifting costs; workover expenses; and gathering, transportation, processing and other expense.

(2) Barnett Shale lease operating costs for the fiscal year ended June 30, 2025 contains a $1.9 million credit from one of our operators due to a joint venture audit, see “Results of Operations” within Item 7. Management’s Discussion and Analysis of Financial Conditions and Results of Operations.

Productive Wells

The following table sets forth the number of productive oil and natural gas wells in which we own an interest as of June 30, 2026.

Company Operated

Non-Operated

Total

​ ​ ​

Gross

​ ​ ​

Net

​ ​ ​

Gross

​ ​ ​

Net

​ ​ ​

Gross

​ ​ ​

Net

Oil

—

—

1,170

178.6

1,170

178.6

Natural gas

—

—

1,481

207.2

1,481

207.2

Total

—

—

2,651

385.8

2,651

385.8

Acreage

The following table sets forth certain information regarding our developed and undeveloped acreage as of June 30, 2026. Developed acreage refers to acreage on which wells have been drilled or completed to a point that would allow production of oil and natural gas in commercial quantities. Undeveloped acreage refers to acreage on which wells have not been drilled or completed to a point that would permit production of oil and natural gas in commercial quantities whether or not the acreage contains proved reserves.

Developed Acreage

Undeveloped Acreage

Total

Field(1)

​ ​ ​

Gross

​ ​ ​

Net

​ ​ ​

Gross

​ ​ ​

Net

​ ​ ​

Gross

​ ​ ​

Net

SCOOP/STACK, Oklahoma(2)

109,715

5,834

—

—

109,715

5,834

Chaveroo Field, New Mexico

1,120

3,408

1,704

4,528

2,264

Jonah Field, Wyoming

5,280

—

—

5,280

Williston Basin, North Dakota

124,800

36,938

8,960

3,136

133,760

40,074

Barnett Shale, Texas

123,777

20,918

—

—

123,777

20,918

Hamilton Dome Field, Wyoming

5,908

1,389

—

—

5,908

1,389

Delhi Field, Louisiana

9,126

2,180

4,510

1,077

13,636

3,257

TexMex, Louisiana, Texas, and New Mexico

27,789

11,220

—

—

27,789

11,220

Louisiana Minerals, Louisiana

—

—

3,624

3,624

Total(3)

379,726

68,775

16,878

5,917

396,604

74,692

(1) Except for our undeveloped acreage at the Williston Basin, North Dakota (see expiration table below), all acreage, including any undeveloped, nonproductive or undrilled acreage, is held by existing production as long as continuous production is maintained in the unit.

(2) Includes 8,595 gross (1,824 net) mineral acres.

(3) This table excludes acreage attributable to small overriding royalty interests retained in various formations in the Texas Giddings Field area. Except for de minimis production that began on two leases during late fiscal year 2019. It does not currently appear likely that we will obtain any significant value from these interests and no reserves have been assigned to any of the Giddings’ interests.

The table below reflects our net undeveloped acreage in Williston Basin, North Dakota as of June 30, 2026 that will expire each year if we do not establish production in paying quantities on the units in which such acreage is included to maintain the lease:

Net Acreage

Fiscal Year

Expiration(1)

—

—

—

—

2031 & beyond

(1) Excludes 2,747 net acres held by existing production as long as continuous production is maintained in the unit.

Markets and Customers

Our production is marketed to third parties in a manner consistent with industry practices. In the United States market where our properties are operated, crude oil, natural gas, and NGLs are readily transportable and marketable. In the Jonah Field, we take our natural gas and NGL working interest production in-kind and market our natural gas separately to different purchasers on six-month contracts. We sell our NGLs to Enterprise Products Partners L.P. We do not currently market our share of oil, natural gas, or NGLs production from any other field separately from the operators’ shares of production. Although we have the right to take our working interest production in-kind, we are currently selling our production through the field operators pursuant to the delivery and pricing terms of their sales contracts. Under such arrangements, we typically do not know the identity of the buyers.

As a non-operator, we are highly dependent on the success of our third-party operators and the decisions made in connection with their operations. With the exception of the Jonah Field, our third-party operators sell our oil, natural gas, and NGLs to purchasers, collect the cash, and distribute the cash to us. In the year ended June 30, 2026, three individual operators, Diversified, Denbury (ExxonMobil), and Foundation, each accounted for more than 10% of our total revenues, collectively representing approximately 46% of our total revenues for the year. In the year ended June 30, 2025, three individual operators, Denbury (ExxonMobil), Diversified, and Foundation, each accounted for more than 10% of our total revenues, collectively representing approximately 51% of our total revenues for the year.

The loss of a purchaser at any of our major producing properties or disruption to pipeline transportation from these fields could adversely affect our net realized pricing and potentially our near-term production levels.

Market Conditions

Prices we receive for crude oil, natural gas, and NGLs are influenced by many factors that are beyond our control, the exact effect of which is difficult to predict. The oil and natural gas industry is a global market impacted by many factors, such as government regulations, particularly in the areas of tariffs, trade sanctions, taxation, energy, climate change and the environment, geopolitical instability, (including ongoing conflicts between Russia and Ukraine, in the Middle East and Venezuela), demand in Asian and European markets, and the extent to which members of OPEC and other oil exporting nations manage oil supply through export quotas. More recently, during the third fiscal quarter, WTI oil prices reached their highest levels since 2022 due to crude oil disruptions at key oil shipping routes in the Middle East, including the Strait of Hormuz, and continue at elevated levels. Natural gas prices are generally determined by North American supply and demand and are also affected by imports and exports of liquefied natural gas. Weather also has a significant impact on demand for natural gas since it is a primary heating source.

Competition

The oil and natural gas industry is highly competitive for prospects, acreage, and capital. Our competitors include major integrated oil and natural gas companies, numerous independent oil and natural gas companies, individuals, and drilling and income programs. Many of our competitors are large, well-established companies with substantially larger operating staff and greater capital resources. Competitors are national, regional, or local in scope and compete on the basis of financial resources, technical prowess or local knowledge. The principal competitive factors in our industry are expertise in given geographical areas and geologic systems and the ability to efficiently conduct operations, achieve technological advantages, identify and acquire economically producible reserves, and obtain capital at rates that allow economic investments.

Risk Management

We are exposed to certain risks relating to our ongoing business operations, including commodity price risk. In accordance with our company strategy and the covenants under the Senior Secured Credit Facility, derivative instruments are utilized to hedge our exposure to price fluctuations and reduce the variability in our cash flows associated with anticipated sales of future oil and natural gas production. We do not enter into derivative contracts for speculative trading purposes.

While there are many different types of derivative instruments available, historically we have used costless collars, stand alone put options, fixed-price swaps and basis swaps to attempt to manage price risk. Costless collar agreements are put and call options used to establish floor and ceiling commodity prices for a fixed volume of production during a certain time period. All costless collar agreements provide for payments to counterparties if the settlement price under the agreement exceeds the ceiling and payments from the counterparties if the settlement price under the agreement is below the floor. Stand alone put options are floors that are purchased for a cost and provide that counterparties make payments to us if the settlement price is below the established floor. The fixed-price swap agreements call for payments to, or receipts from, counterparties depending on whether the index price of oil or natural gas for the period is greater or less than the fixed price established for the period contracted under the fixed-price swap agreement. The basis swaps agreements effectively lock in a price differential between regional prices (i.e., Inside FERC’s Northwest Pipeline Corp Rocky Mountains) where the product is sold and the relevant pricing index under which the natural gas production is hedged (i.e., NYMEX Henry Hub).

It is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. For the derivative contracts settled during fiscal 2026 and 2025, we did not post collateral. In accordance with our Senior Secured Credit Facility, we have been and may be required in the future to enter into hedges if we meet certain utilization levels of the borrowing base under the credit facility. We intend to remain in compliance with these covenants and will enter into derivative contracts from time to time to meet the requirements. Additionally, depending on market conditions, financial and other considerations we may enter into additional hedges to meet our objectives of increasing value to shareholders. We may also, from time to time, restructure existing derivative contracts or enter into new transactions to effectively modify the terms of current contracts in order to improve the pricing parameters in existing contracts. See Item 7A. Quantitative and Qualitative Disclosures About Market Risk and Note 7, “Derivatives” to our consolidated financial statements in Item 8. Financial Statements and Supplementary Data for additional information.

Government Regulation

As an oil and natural gas exploration and production company, our interests are subject to numerous legal requirements.

Regulation of Oil and Natural Gas Production

Federal, state and local authorities have promulgated extensive rules covering oil and natural gas exploration, production and related operations. Those regulations require our third-party operator to obtain permits, post bonds and submit reports. They also may address conservation, including unitization or pooling of oil and natural gas properties, well locations, the method of drilling and casing wells, surface use and restoration of properties where wells are drilled,

sourcing and disposal of water used in the process of drilling, completion and abandonment, the establishment of maximum rates of production from wells, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce and to limit the number of wells or the locations at which we can produce. Moreover, many states impose a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within their jurisdictions. Failure to comply with any applicable legal requirements may result in substantial penalties. Because such regulations are frequently amended or reinterpreted, we are unable to predict future compliance costs or impacts. Significant expenditures may be required to comply with governmental laws and regulations, however, and may have a material adverse effect on our financial condition and results of operations.

Regulation of Transportation of Oil and Natural Gas

The prices for crude oil, condensate and natural gas liquids and natural gas are negotiated and not currently regulated. However, Congress, which has been active in oil and natural gas regulation, could impose price controls in the future.

Our sales of crude oil and natural gas are affected by the availability, terms and cost of transportation. The Federal Energy Regulatory Commission (“FERC”) primarily regulates interstate oil and natural gas transportation rates. In some circumstances, FERC regulations also may affect intrastate pipelines. In addition, states may impose on intrastate pipelines various obligations relating to such matters as safety, environmental protection, nondiscriminatory take and pay rates. The basis for intrastate oil and natural gas pipeline regulation, and the degree of regulatory oversight and scrutiny given to such matters, vary from state to state. To the extent effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil and natural gas transportation rates will not affect our business in any way that is of material difference from those of our competitors who are similarly situated.

Environmental Matters

Our properties are subject to extensive and changing federal, state and local laws and regulations relating to the protection of the environment, worker safety and human health. Such requirements may address:

● the generation, storage, handling, emission, transportation and disposal of materials;

● reclamation or remediation of sites, including former operating areas;

● the acquisition of a permit or other authorization;

● air emissions;

● protection of water supplies;

● limits on construction, drilling and other activities in wilderness or other environmentally sensitive areas; and

● assessment of environmental impacts.

Failure to comply with such requirements may result in a variety of sanctions, including fines, administrative orders and injunctions. In addition, issuing authorities may revoke, adversely condition or deny permits necessary for the operations of our operators. In the opinion of management, our properties are in substantial compliance with applicable environmental laws and regulations, and we have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on our company, as well as the oil and natural gas industry in general. Significant environmental requirements that may affect the operations of our operators are described below.

The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and comparable state statutes impose strict liability, and in some cases joint and several liability, on owners and operators of sites and on persons who arranged for the disposal of “hazardous substances” found at such sites. It is not uncommon for neighboring landowners or other third parties to also file claims for personal injury and property damage allegedly caused by any hazardous substances released into the environment. Although CERCLA currently excludes petroleum from its definition of “hazardous substance,” the operations performed by our operators do entail handling other chemicals that may be subject to the statute. In addition, state laws affecting our properties may impose cleanup liability relating to petroleum and petroleum related products. The Federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes govern the disposal of “solid waste” and “hazardous waste.” Violations may result in

substantial fines. Although RCRA currently classifies certain oil field wastes as “non-hazardous,” such exploration and production wastes could be reclassified as hazardous, thereby subjecting the operations of our operators to more stringent handling and disposal requirements. In some circumstances, moreover, RCRA authorizes both the federal government and private persons to seek injunctions requiring the cleanup of wastes, whether hazardous or non-hazardous.

The Endangered Species Act (“ESA”) protects fish, wildlife and plants that are listed as threatened or endangered. Under the ESA, exploration and production operations may not significantly impair or jeopardize a protected species or its habitat. The ESA provides for criminal penalties for willful violations. The operations or our operators also may be subject to other statutes that protect animals and plants such as the Migratory Bird Treaty Act. Although we believe that our properties are in compliance in all material respects with such statutes, any change in these statutes or any reclassification of a species as endangered could subject our company (directly or indirectly through our third-party operators) to significant expenses to modify operations, could force discontinuation of certain operations altogether and could limit the locations our third-party operators may utilize in the future.

The Clean Air Act (“CAA”) is the comprehensive federal law addressing sources of air emissions. Oil and natural gas production and natural gas processing operations are among the many source categories subject to the CAA. Regulated emissions from oil and natural gas operations include sulfur dioxide, volatile organic compounds (“VOCs”) and hazardous air pollutants such as benzene, among others.

In particular, the Environmental Protection Agency (“EPA”) announced regulations in December 2023 that imposed more comprehensive restrictions on emissions of methane (a greenhouse gas) and VOCs from new, existing, and modified facilities in the oil and gas sector (such as wells and storage tank batteries). Among other things, the rule set new emissions standards for certain equipment; required routine monitoring for and repair of leaks at well sites, centralized production facilities, and compressor stations; limited flaring from existing oil wells; and prohibited flaring from new oil wells. EPA also established a “Super Emitter Program” to authorize third parties to detect “super emitter events” at operators’ sites and report them to EPA. The regulations did provide phase-in periods for certain requirements, while State plans for existing sources were due 24 months after the rule’s effective date. States were given the option of either adopting the rule’s presumptive standards or developing their own requirements that are at least as strict as EPA’s. In 2024, however, EPA agreed to reconsider certain technical aspects of the regulations, which resulted in narrow changes to requirements for temporary flaring and monitoring of vent gas. In the meantime, EPA announced in 2025 it was conducting a more comprehensive reconsideration and extended various compliance deadlines in the rule. The results of that review are uncertain. But if the regulations remain as announced in December 2023, or if future such requirements requiring the installation of more sophisticated pollution control equipment are adopted, they could have a material adverse impact on our business, results of operations and financial condition.

The Clean Water Act (the “CWA”) is the primary federal law controlling the discharge of produced waters and other pollutants into waters of the United States. Permits must be obtained for such discharges and to conduct construction activities in waters and wetlands. Some states also require permits for discharges or operations that may impact groundwater.

The CAA, CWA and comparable state statutes authorize civil, criminal and administrative penalties for violations. Further, the CWA and Oil Pollution Act may impose liability on owners or operators of onshore facilities that impact surface waters.

Pursuant to the Safe Drinking Water Act, the EPA (or an authorized state) regulates the construction, operation, permitting, and closure of injection wells used to place oil and natural gas wastes and other fluids underground for enhanced hydrocarbon recovery, storage or disposal. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. Underground injection associated with oil and gas operations, particularly the disposal of produced water, has been linked in some cases to localized earthquakes. This in turn has led to new legislative and regulatory initiatives, which have the potential to restrict injection in certain wells or limit operations in certain areas.

Certain of the oil and natural gas production in which we have an interest is developed from unconventional sources that require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection into the formation of water, sand and chemicals under pressure to stimulate production. From time to time, legislation has been proposed in the United States Congress to repeal the Safe Drinking Water Act’s exemption for hydraulic fracturing from the definition of “underground injection” and to require federal permitting of hydraulic fracturing. If ever enacted, such legislation would add to costs for hydraulic fracturing.

Scrutiny of hydraulic fracturing activities continues in other ways. Several states where our properties are located have proposed or adopted legislative or regulatory restrictions on hydraulic fracturing. A number of municipalities likewise have enacted bans on hydraulic fracturing. We cannot predict whether any other legislation restricting hydraulic fracturing will be enacted and if so, what its provisions would be. If additional levels of regulation and permits were to be required through the adoption of new laws and regulations at the federal, state or local level, it could lead to delays, increased operating costs and process prohibitions that could materially adversely affect our revenue and results of operations.

The National Environmental Policy Act (“NEPA”) requires federal agencies to assess the environmental effects of their proposed actions prior to making decisions. Among the broad range of actions covered by NEPA are decisions on permit applications and federal land management. Many of the activities of our third-party operators involve federal decisions subject to NEPA. Such federal actions may trigger robust NEPA review, which could lead to delays and increased costs that could materially adversely affect our revenues and results of operations. In response to recent court decisions, and direction from the second Trump Administration to expedite permit approvals, federal agencies started updating their NEPA procedures in 2025, but the long-term effects of those revisions are uncertain. In the absence of precedents, application of the new procedures may be unclear, and nongovernmental organizations are expected to bring legal challenges, which could adversely affect the assessment of projects ranging from oil and gas leasing to development on public and Indian lands.

Climate Change

Climate change has become a major public concern and policy issue in the United States and around the world. Much of the debate has focused on greenhouse gas (“GHG”) emissions from oil and natural gas, particularly carbon dioxide and methane.

In the United States, there is no comprehensive federal regulatory statute addressing climate change, although Congress does periodically consider such measures. At the federal level, the United States therefore has primarily addressed climate change through executive actions and regulatory initiatives pursuant to existing statutes. These have included participation in international agreements on climate change, presidential commitments to reduce greenhouse gas, various executive orders limiting land available for oil and gas leasing, and Clean Air Act rules (such as the regulation announced in December 2023 to reduce methane emissions from the oil and gas sector). In his second Administration, President Trump has reversed, or indicated that he intended to reverse, many of those initiatives. Even if those efforts are successful, several states have already implemented or are considering programs to reduce GHG emissions. These include cap and trade programs, promotion of alternative forms of energy, transportation standards and restrictions on particular GHGs. New Mexico, for example, is requiring oil and gas operators to capture 98% of their produced natural gas by December 31, 2026, and is limiting most venting and flaring. Such efforts are expected to continue in some states. To the extent that new climate change measures are adopted, our business may be adversely impacted.

In addition, recent court decisions have left open the question of whether tort claims alleging property damage may proceed under state common law against entities responsible for GHG emissions. Some states also have enacted statutes authorizing recovery of adaptation costs from certain fossil fuel producers or refiners. Thus, there is some litigation risk for state law claims.

Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher GHG emitting energy sources, for example, our products would become more desirable in the market with more stringent limitations on GHG emissions. To the extent that our products are competing with lower

GHG emitting energy sources such as solar and wind, our products may become less desirable in the market with such government intervention. In 2022, the United States enacted the Inflation Reduction Act that, among other things, created a series of financial incentives intended to discourage use of oil and natural gas (including imposing a fee on methane emissions) and to promote alternative sources of energy. Pursuant to that Act, EPA announced a rule in 2024 that would have implemented the program for collecting the annual “Waste Emissions Charge” on certain excess methane emissions from oil and gas facilities. By statute, the charge would have been $900 per metric ton of methane for 2024, $1,200 per metric ton for 2025, and $1,500 per metric ton each year thereafter. But in 2025 Congress invalidated the EPA’s rule and postponed the methane reduction charge to 2034. We cannot predict with any certainty at this time how such market-based climate incentives may affect the operations of our oil and natural gas properties.

Various studies on climate change indicate that extreme weather conditions and other risks may occur in the future in the areas where we operate. Although we have not experienced any material impact from such extreme conditions to date, no assurance can be given that they will not have a material adverse effect on our business in the future.

See discussion captioned “Government regulation and liability for oil and natural gas operations and environmental matters may adversely affect our business and results of operations” in