What changed in this filing

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Item 1. Business

2026-03-31 compared with 2025-03-31 · 396 added, 429 removed, 255 unchanged (76% of the section changed)

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Following the merger, we refocused our business plan on the acquisition, exploration, development and production of oil and natural gas resources in the United States.

As discussed in greater detail below under “ Business Strategy—Merger Agreement ”, on October 31, 2025, we entered into an Agreement and Plan of Merger (the “ Merger Agreement ”), between the Company, NP Merger Sub, LLC, a Delaware limited liability company and wholly-owned subsidiary of the Company (“ First Merger Sub ”), COG Merger Sub, LLC, a Delaware limited liability company and wholly-owned subsidiary of the Company (“ Second Merger Sub ,” and together with First Merger Sub, the “ Merger Subs ”), North Peak Oil & Gas, LLC, a Delaware limited liability company (“ NPOG ”), Century Oil and Gas Sub-Holdings, LLC, a Delaware limited liability company (“ COG ,” and together with NPOG, the “ Acquired Companies ”), and, solely for purposes of the specified provisions therein, North Peak Oil & Gas Holdings, LLC, a Delaware limited partnership (“ North Peak ”).

Pursuant to the Merger Agreement, on October 31, 2025, (a) First Merger Sub merged with and into NPOG, with NPOG being the surviving entity and a wholly-owned subsidiary of the Company and (b) Second Merger Sub merged with and into COG, with COG being the surviving entity and a wholly-owned subsidiary of the Company (the “ Mergers ”).

Our corporate headquarters are located in approximately 5,200 square feet of office space at 575 N.

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In particular, we focus on legacy proven properties where there is a long production history, well defined geology and existing infrastructure that can be leveraged when applying modern field management technologies.

Our current properties are located in the San Andres formation of the Permian Basin situated in West Texas and eastern New Mexico (the “ Permian Basin ”) and in the Denver-Julesberg Basin (“ D-J Basin ”) in Colorado and Wyoming.

As of December 31, 2024, we held approximately 14,105 net Permian Basin acres located in Chaves and Roosevelt Counties, New Mexico, through our wholly-owned subsidiary, Pacific Energy Development Corp.

(“ PEDCO ”), and which are operated by our wholly-owned operating subsidiary, Ridgeway Arizona Oil Corp.

(“ RAZO ”), which asset we refer to as our “ Permian Basin Asset .” Also as of December 31, 2024, we held approximately 18,669 net D-J Basin acres located in Weld and Morgan Counties, Colorado, and Laramie County, Wyoming, through our wholly-owned subsidiary, PRH Holdings LLC (“ PRH ”), and which are operated by our wholly-owned operating subsidiary, Red Hawk Petroleum, LLC (“ Red Hawk ”), which asset we refer to as our “ D-J Basin Asset .” As of December 31, 2024, we held interests in 35 gross (33.5 net) wells in our Permian Basin Asset, of which 28 gross (26.5 net) wells are active producers, five gross (five net) wells are inactive, and two gross (two net) wells are active salt water disposal wells (“ SWD’ s”), all of which are held by PEDCO and operated by RAZO, and interests in 82 gross (21.9 net) wells in our D-J Basin Asset held by PRH, all of which 17 gross (15.4 net) wells are operated by Red Hawk and currently producing, 48 gross (6.5 net) wells are non-operated, and 17 wells have an after-payout interest.

Our current properties are located in the Denver-Julesberg Basin (“ D-J Basin ”) in Colorado and Wyoming, the Powder River Basin (“ PRB ”) in Wyoming, and in the San Andres formation of the Permian Basin situated in West Texas and eastern New Mexico (the “ Permian Basin ”).

As of December 31, 2025, we held approximately 99,561 net acres in the D-J Basin located in Weld and Morgan Counties, Colorado and Laramie County, Wyoming, through our wholly-owned subsidiaries, PRH Holdings LLC (“ PRH ”) and NPOG (the “ D-J Basin Asset ”), which assets are operated by the Company’s wholly-owned operating subsidiaries, Red Hawk Petroleum, LLC (“ Red Hawk ”), North Silo Resources, LLC (“ NSR ”), and Longs Peak Resources, LLC (“ LPR ”).

On April 3, 2025, effective January 1, 2025, the Company sold all of its legacy 17 gross (15.4 net) operated wells in the D-J Basin in order to reduce plugging and abandonment liabilities and recurring operating expenses.

The Company retained ownership of the associated leasehold interests, as these legacy wells no longer provided meaningful oil and gas production.

As of December 31, 2025, the Company held approximately 201,886 net acres in the Powder River Basin, predominantly located in Laramie and Campbell Counties, Wyoming, through its wholly-owned subsidiary COG .

These assets are operated by the Company’s wholly-owned operating subsidiaries, COG, Navigation Powder River, LLC (“ NPR ”), and Pine Haven Resources, LLC (“ Pine Haven ”), and are referred to as the “Powder River Basin Asset” or the “PRB Asset.”

As of December 31, 2025, we held approximately 14,105 net acres in the Permian Basin located in Chaves and Roosevelt Counties, New Mexico, through our wholly-owned subsidiary, Pacific Energy Development Corp.

These assets are operated by our wholly-owned operating subsidiary, Ridgeway Arizona Oil Corp.

(“ RAZO ”), and are collectively referred to as our “Permian Basin Asset.”

As of December 31, 2025, we held interests in 184 gross (79.4 net) wells, consisting of 170 producing wells, three saltwater disposal wells, and 11 drilled but uncompleted wells (“ DUCs ”) in the D-J Basin Asset.

Of these wells, 74 gross (66.9 net) were operated and 110 gross (12.5 net) were non-operated.

In the PRB Asset, we held interests in 156 gross (135.4 net) wells, consisting of 140 producing wells, 15 injection wells, and one saltwater disposal well.

Of these wells, 16 gross (1.4 net) were non-operated.

In the Permian Basin, we held interests in 38 gross (34.5 net) wells consisting of 34 producing wells, two injection wells, and two saltwater disposal wells.

Business Strategy

We believe that horizontal development and exploitation of conventional assets in the Permian Basin and development of the Wattenberg and Wattenberg Extension in the D-J Basin, represent among the most economic oil and natural gas plays in the U.S.

We plan to optimize our existing assets and opportunistically seek additional acreage proximate to our currently held core acreage, as well as other attractive onshore U.S.

oil and gas assets that fit our acquisition criteria, that Company management believes can be developed using our technical and operating expertise and be accretive to stockholder value.

We believe that horizontal development and exploitation of conventional and unconventional oil and gas assets in the Rockies region, including the D-J and Powder River Basins, and the Permian Basin, represent among the most economic oil and natural gas plays in the U.S.

We plan to optimize our existing assets and opportunistically seek additional acreage proximate to our currently held core acreage, as well as target other acquisitions in the Rockies region that fit our acquisition criteria.

We believe there is a significant opportunity to build a leading oil and gas company in the Rockies region through both organic growth and acquisitions on terms that are more attractive than what we see in other oil and gas producing basins.

Specifically, we seek to increase stockholder value through the following strategies:

Grow production, cash flow and reserves by developing our operated drilling inventory and participating opportunistically in non-operated projects.

We believe our extensive inventory of drilling locations in the Permian Basin and the D-J Basin, combined with our operating expertise, will enable us to continue to deliver accretive production, cash flow and reserves growth.

We believe our extensive inventory of drilling locations in the D-J Basin, Powder River Basin, and Permian Basin, combined with our operating expertise, will enable us to continue to deliver accretive production, cash flow and reserves growth.

We believe the location, concentration and scale of our core leasehold positions, coupled with our technical understanding of the reservoirs, will allow us to efficiently develop our core areas and to allocate capital to maximize the value of our resource base.

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We believe our attention to detail and application of the latest industry advances in horizontal drilling, completions design, frac intensity and locally optimal frac fluids will allow us to successfully develop our properties.

Optimization of well density and configuration.

We own properties that are legacy oil fields characterized by widespread vertical and horizontal development and geological well control.

We utilize the extensive geological, petrophysical and production data of such legacy properties to confirm optimal well spacing and configuration using modern reservoir evaluation methodologies.

Optimization of development plans, well density and configuration.

We own properties that are located in oil and gas producing basins that are geologically well defined, characterized by widespread vertical and horizontal development and geological well control.

We utilize the extensive geological, petrophysical and production data of such properties to confirm optimal development plans, well spacing and configuration using modern reservoir evaluation methodologies.

Maintain a high degree of operational control and/or form partnerships which allow for a high degree of control over non-operated properties.

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Leverage extensive deal flow, technical and operational experience to evaluate and execute accretive acquisition opportunities.

Our management and technical teams have an extensive track record of forming and building oil and gas businesses.

Our management and technical teams have an extensive track record of forming, buying, building and selling oil and gas businesses.

We also have significant expertise in successfully sourcing, evaluating and executing acquisition opportunities.

We believe our understanding of the geology, geophysics and reservoir properties of potential acquisition targets will allow us to identify and acquire highly prospective acreage in order to grow our reserve base and maximize stockholder value.

We believe our understanding of the business, financial, geology, geophysics and reservoir properties of potential acquisition targets will allow us to identify and acquire highly prospective acquisitions and leasing opportunities in order to grow our reserve base and maximize stockholder value.

Preserve financial flexibility to pursue organic and external growth opportunities.

We intend to maintain a disciplined financial profile in order to provide flexibility across various commodity and market cycles.

We also are committed to developing and monitoring environmental, social and governance (“ ESG ”) initiatives and the Board of Directors plans to evaluate the potential adoption of ESG initiatives from time to time, provided that no definitive ESG plans have been adopted to date.

Our strategy is to be the operator and/or a significant working interest owner, directly or through our subsidiaries and joint ventures, in the majority of our Permian Basin acreage so we can dictate the pace of development in order to execute our business plan.

Our D-J Basin strategy is to participate in projects we deem highly economic on an operated or non-operated basis as our acreage position does not always allow for us to serve as operator in the D-J Basin.

Our net capital expenditures for 2025 are estimated at the time of this Annual Report to range between $27 million to $33 million.

This estimate includes a range of $24.5 million to $30.5 million for drilling and completion costs on our Permian Basin and D-J Basin Assets and approximately $2.5 million in estimated capital expenditures for ESP purchases, rod pump conversions, recompletions, well cleanouts, leasing, facilities, remediation and other miscellaneous capital expenses.

We anticipate that approximately 70% to 75% of our expected capital expenditures for 2025 will be allocated to development in the D-J Basin under our February 2025 joint development agreement entered into with a large private equity-backed D-J Basin operator and our Participation Agreement and Area of Mutual Interest (“ AMI ”) entered into in August 2024 with a private operator.

This estimate does not include expenditures for acquisitions or other projects that may arise but are not currently anticipated.

Our strategy is to be the operator and/or a significant working interest owner, directly or through our subsidiaries and joint ventures, in the majority of our acreage so we can dictate the pace of development in order to execute our business plan.

In areas we deem highly economic and do not have a high enough working interest to serve as operator, we seek to participate in projects if returns match or exceed other projects in our portfolio.

Due to the fragmented nature of acreage positions in some of our holdings, our ownership interest does not always allow us to serve as the operator.

Our net capital expenditures for 2026 are estimated at the time of this filing to range between $16 million to $20 million.

This estimate includes a range of $6 million to $7 million for drilling and completion costs on our D-J Basin Assets (of which approximately $3 million is carry over from our 2025 program) and approximately $10 million to $13 million in estimated capital expenditures for optimization projects on the newly acquired assets from the Mergers.

These optimization projects include jet pump to rod pump or gas lift conversions, electronic submersible pump (ESP) to rod pump conversions, compression optimization projects, recompletions, and well cleanouts that are expected to materially lower lease operating expenses on our operated assets going forward.

Other minor capital expenditures included in these figures are leasing, facilities, remediation and other miscellaneous capital expenses.

We anticipate that approximately 90% of our expected capital expenditures for 2026 will be allocated to the D-J Basin and 10% will be allocated collectively to the Powder River and Permian Basin.

These estimates do not include any expenditures for acquisitions or other projects that may arise but are not currently anticipated.

We are evaluating future development plans for late 2026 and 2027, as we integrate the assets and operations acquired in the Mergers and work to execute the near-term optimization program outlined above.

We periodically review our capital expenditures and adjust our capital forecasts and allocations based on liquidity, drilling results, leasehold acquisition opportunities, partner non-consents, proposals from third party operators, and commodity prices, while prioritizing our financial strength and liquidity (see “ Part I ” – “ Item 1A.

Risk Factors ”).

We plan to continue to evaluate D-J Basin well proposals as received from third party operators and participate in those we deem most economic and prospective.

If new proposals are received that meet our economic thresholds and require material capital expenditures, we have flexibility to move capital from our Permian Asset to our D-J Basin Asset, or vice versa, as our Permian Asset is 100% operated and nearly all held by production (“ HBP ”), allowing for flexibility of timing on development.

We plan to continue to evaluate D-J Basin non-operated well proposals as received from third party operators and participate in those we deem most economic and prospective.

If new proposals are received that meet our economic thresholds and require material capital expenditures, we have flexibility to expand our capital program or move capital from our operated D-J Basin, Powder River Basin, and Permian Basin assets, allowing for flexibility on timing of development.

Our 2026 development program is based upon our current outlook for the year and is subject to revision, if and as necessary, to react to market conditions, product pricing, contractor availability, requisite permitting, capital availability, partner non-consents, capital allocation changes between assets, acquisitions, divestitures and other adjustments determined by the Company in the best interest of its shareholders while prioritizing our financial strength and liquidity.

We expect that we will have sufficient cash available to meet our needs over the next 12 months after the filing of this report and in the foreseeable future, including to fund our 2025 development program, discussed above, which cash we anticipate being available from (i) projected cash flow from our operations, (ii) existing cash on hand, (iii) equity infusions or loans (which may be convertible) made available from Dr.

Kukes, our former CEO and newly appointed Executive Chairman of the Company's Board of Directors, which funding Dr.

Kukes is under no obligation to provide, (iv) public or private debt or equity financings, including up to $8.0 million in securities which we may sell in the future in “at the market offerings”, pursuant to a Sales Agreement entered into on December 20, 2024, with Roth Capital Partners, LLC (the “ Lead Agent ”), and A.G.P./Alliance Global Partners (“ AGP ” and, together with the Lead Agent, the “ Agents ”)(discussed in greater detail below under “ Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Financing ” (under which we have sold no shares to date), and (v) funding through credit or loan facilities, including under the Company’s reserve-based lending facility (“ RBL ”) with Citibank, N.A., as administrative agent, which provides for an initial borrowing base of $20 million and an aggregate maximum revolving credit amount of $250 million (of which none has been drawn down by the Company to date).

We expect that we will have sufficient cash available to meet our needs over the next 12 months after the filing of this report and in the foreseeable future, including to fund the remainder of our 2026 development program, discussed above, which cash we anticipate being available from (i) projected cash flow from our operations, (ii) existing cash on hand, (iii) public or private debt or equity financings, including up to $7.6 million in securities which we may sell in the future in “at the market offerings”, pursuant to a Sales Agreement entered into on December 20, 2024, with Roth Capital Partners, LLC (the “ Lead Agent ”), and A.G.P./Alliance Global Partners (“ AGP ” and, together with the Lead Agent, the “ Agents ”) discussed in greater detail below under “Liquidity and Capital Resources—Financing” (under which we have sold 24,498 shares of common stock to date at a sales prices ranging between $14.32 to $16.02 per share), and (iv) funding through credit or loan facilities, including under the Company’s A&R Credit Agreement with Citibank, N.A., as administrative agent, which provides for an initial borrowing base of $120 million and an aggregate maximum revolving credit amount of $250 million (of which $98 million has been drawn down by the Company to date), as discussed in greater detail below under “ Liquidity and Capital Resources ”.

In addition, we may seek additional funding through asset sales, farm-out arrangements, and credit facilities to fund potential acquisitions during the remainder of 2026.

The following chart reflects our current organizational structure:

*Represents percentage of total voting power based on 91,339,385 shares of common stock outstanding as of March 28, 2025, with beneficial ownership calculated in accordance with Rule 13d-3 of the Exchange Act.

Holdings of The SGK 2018 Revocable Trust are also included in holdings of Senior Management and the Board – See “ Part III ” — “ Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters .”

Participations Agreements Related to D-J Basin Assets

On August 21, 2024, the Company, through PRH, entered into a five-year Participation Agreement with a large private equity-backed D-J Basin exploration and production company with extensive operational experience (“ Joint Development Party ”), whereby the Joint Development Party assigned to PRH a 30% interest in approximately 7,607 net acres of existing oil and gas leases and PRH assigned to the Joint Development Party a 70% interest in approximately 3,166 net acres of oil and gas leases, all located within the SW Pony Prospect in the D-J Basin in Weld County, Colorado.

Additionally, to facilitate joint development of the SW Pony Prospect, the parties agreed to an Area of Mutual Interest covering approximately 16,900 gross acres wherein the parties have the opportunity to participate in subsequent leasehold acquisitions proportionate to their working interest under the Participation Agreement.

Each party’s participation is based on their proportionate share of the total acquisition cost.

The Company participated in six wells which were drilled and completed in 2024 (the Harlequin wells), and four wells which were drilled and completed in the fourth quarter of 2025 (three Mavericks wells and one Jaws well), all of which were within this Area of Mutual Interest.

In February 2025, the Company entered into a Joint Development Agreement with a large, Denver, Colorado-based private equity-backed D-J Basin exploration and production (E&P) Company with extensive operational experience (the “ Operator ”), pursuant to which the parties agreed to jointly participate in the expansion and development of the Company’s Roth and Amber drilling spacing units (DSUs) located in Weld County, Colorado, with the Operator paying to the Company $1.7 million, the Company agreeing to amend the Company’s existing Roth and Amber DSUs to increase each to 1,600 acres and transferring operatorship of the DSUs to the Operator, and the parties agreeing to jointly participate in the development of the Roth and Amber DSUs.

The Roth wells were drilled and completed in the fourth quarter of 2025.

The Operator has until May 10, 2026, to make an election to acquire up to 50% of the Company’s working interest in the Amber DSU at an acquisition price of approximately $2.5 million, with no election having been made to date.

Merger Agreement

On October 31, 2025 (the “ Closing ”), we entered into the Agreement and Plan of Merger with NP Merger Sub, LLC, a Delaware limited liability company and wholly owned subsidiary of the Company, COG Merger Sub, LLC, a Delaware limited liability company and wholly owned subsidiary of the Company, North Peak Oil & Gas, LLC, a Delaware limited liability company, Century Oil and Gas Sub-Holdings, LLC, a Delaware limited liability company, and, solely for purposes of the specified provisions therein, North Peak Oil & Gas Holdings, LLC, a Delaware limited partnership.

Pursuant to the Merger Agreement, (a) First Merger Sub merged with and into NPOG, with NPOG being the surviving entity and a wholly owned subsidiary of the Company, and (b) Second Merger Sub merged with and into COG, with COG being the surviving entity and a wholly owned subsidiary of the Company.

Subject to the terms and conditions of the Merger Agreement, all of the issued and outstanding limited liability company interests of each of NPOG and COG were automatically converted into the right to receive an aggregate of 10,650,000 validly issued, fully paid and nonassessable shares of newly designated Series A Convertible Preferred Stock of the Company (the “ Merger Preferred Shares ”), par value $0.001 per share (the “ Series A Preferred Stock ”), which shares were issued to Century Oil and Gas Holdings, LLC, a Delaware limited liability company (“ Century ”) and North Peak.

The Series A Preferred Stock automatically converted into shares of common stock of the Company, par value $0.001 per share (the “ Automatic Conversion ”), at a ratio of 0.5-to-1, effective February 27, 2026, following the expiration of the twenty calendar day period commencing on the distribution of an information statement to the Company’s shareholders in accordance with Rule 14c-2 of Regulation 14C promulgated under the Exchange Act (the “ Automatic Conversion Date ”).

On the Automatic Conversion Date, the Merger Preferred Shares converted into an aggregate of 5,325,000 shares of Company common stock.

Amended and Restated Credit Agreement

On October 31, 2025, the Company entered into an Amended and Restated Credit Agreement (the “ A&R Credit Agreement ”), which amended and restated that prior senior secured revolving credit agreement entered into on September 11, 2024 (the “ Original Credit Agreement ”) among the Company, as borrower, Citibank, N.A., as administrative agent (the “ Administrative Agent ”), and the lenders from time to time party thereto (the “ Lenders ”).

The A&R Credit Agreement has a maturity date of October 31, 2029.

The A&R Credit Agreement provides for an initial borrowing base and aggregate elected commitments of $120 million and an aggregate maximum revolving credit amount of $250 million.

The borrowing base is scheduled to be redetermined semiannually on or about April 1 and October 1 of each calendar year, commencing on April 1, 2026, and is subject to additional adjustments from time to time, including for certain asset sales, elimination or reduction of hedge positions and title defects.

The A&R Credit Agreement contains additional restrictive covenants that limit the ability of the Company and its subsidiaries to, among other things, incur additional indebtedness, incur additional liens, enter into mergers and consolidations, make or declare dividends, make investments and loans, engage in transactions with affiliates.

In connection with the closing of the Mergers, the Company drew $87 million under the A&R Credit Agreement.

The Company subsequently borrowed an additional $6.0 million on January 8, 2026 and $5.0 million on February 5, 2026.

The proceeds from these borrowings are expected to be used to fund the Company’s participation in certain non-operated well operations and to pay other Company obligations.

A total of $98 million is currently outstanding under the A&R Credit Agreement as of the date of this filing.

PIPE Offering

Concurrently with the Closing of the Mergers, certain investors (the “ PIPE Investors ”) subscribed for and purchased an aggregate of 6,363,637 shares of Series A Preferred Stock (the “ PIPE Preferred Shares ”), at a price per share equal to $5.50 per share (the “ Purchase Price ”) ($11.00 per share on a post -reverse stock split basis) , pursuant to their entry into Series A Convertible Preferred Stock Subscription Agreements in favor of the Company (the “ Subscription Agreements ”).

On the Automatic Conversion Date, the PIPE Preferred Shares converted into 3,181,818 shares of Company common stock (the “ PIPE Conversion Shares ”).

The PIPE Investors included (a) The SGK 2018 Revocable Trust, a family trust of which Dr.

Simon Kukes, the then Executive Chairman of the Company is trustee and beneficiary ($15,409,977);

(b) American Resources, Inc., an entity owned and controlled by J.

Douglas Schick, the Chief Executive Officer, President and member of the Board ($250,003);

Moore, the Executive Vice President, General Counsel and Secretary of the Company ($25,003);

Scelfo Revocable Trust Dated October 8, 2003, a trust of which John J.

Scelfo, a member of the Board, is trustee and beneficiary ($550,000);

Crook, the Chief Commercial Officer of the Company ($25,003);

(f) J PED, LLC, an entity affiliated with Juniper Capital Advisors, L.P.

(“ Juniper ”) ($18,550,004);

(g) Reagan T.

Dukes, the then Chief Executive Officer of the Acquired Companies, who was appointed Chief Operating Officer of the Company at the Closing of the Mergers ($52,503) and (h) Robert J.

Long, the then Chief Financial Officer of the Acquired Companies, who was appointed Chief Financial Officer, Treasurer and Principal Accounting/Financial Officer of the Company at the Closing of the Mergers ($52,503).

The PIPE Financing closed concurrently with the Mergers and the $35,000,004 of net proceeds raised by the Company pursuant to the PIPE Financing was used to pay off certain liabilities of the Acquired Companies in connection with the Mergers and certain expenses of the PIPE Financing and Mergers.

Second Amended and Restated Designation of Series A Convertible Preferred Stock

In preparation for the Closing of the Mergers, the Board of Directors approved the Second Amended and Restated Certificate of Designations establishing the rights, preferences, and limitations of the Company’s Series A Convertible Preferred Stock on October 29, 2025, which was filed with the Texas Secretary of State on October 31, 2025.

A total of 17,013,637 shares of Series A Preferred Stock were designated.

Except as required by law or the designation, Series A Preferred Stockholders had no voting rights, except the right to elect one director (the “ Series A Director ”) until the Automatic Conversion Date, with Josh Schmidt serving as such director.

Holders of Series A Preferred Stock were entitled to certain protective provisions, requiring approval by a majority in interest of outstanding shares for actions such as amending governing documents, changing board composition, issuing new securities, major acquisitions or disposals, indebtedness above $500,000, executive appointments, and other material corporate actions.

The holders of Series A Preferred Stock were provided no dividend rights, and in the event of liquidation, dissolution, or winding-up, Series A holders were to receive distributions pari passu with common shareholders, as if their shares were converted to common stock.

All of the 17,013,627 then outstanding shares of Series A Preferred Stock converted on the Automatic Conversion Date, into an aggregate of 8,506,818 shares of the Company common stock in a ratio of 0.5-for-1.

Additionally, on February 27, 2026, the Company, after approval of the Board of Directors and the stockholders pursuant to the Written Consent, filed a Second Amended and Restated Certificate of Formation of the Company, which among other things, terminated the designation of the Series A Preferred Stock.

As such, as of the date of this Report, we have no Series A Preferred Stock outstanding or designated.

The oil and natural gas industry is highly competitive.

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Many of our competitors have a longer history of operations than we have, and many of them have also demonstrated the ability to operate through industry cycles.

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 A&R Credit Agreement, derivative instruments are occasionally utilized to hedge our exposure to price fluctuations and reduce the variability in our cash flows associated with anticipated sales of future oil, natural gas and natural gas liquids production.

We do not enter into derivative contracts for speculative trading purposes.

While there are many different types of derivative instruments available, we have used costless collars, producer three-way collars, standalone put options, fixed-price swaps and basis swaps to attempt to manage price risk.

Costless collar and three-way producer collar agreements are combinations of put and call options used to establish floor and ceiling commodity prices for a fixed volume of production during a certain time period.

All collar agreements provide for payments between the counterparties if the settlement price under the agreement exceeds the ceiling or if the settlement price under the agreement is below the floor.

Standalone 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 where the product is sold and the relevant pricing index under which oil or natural gas production is hedged.

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.

We will continue to evaluate the benefit of employing derivatives in the future.

Our hedge strategies and objectives may change as our operational profile changes see “ Item 8 Financial Statements and Supplementary Data ” – “ Note 10 - Derivatives )”for additional information.

Competitive Strengths

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Low-Cost Development .

Shallow conventional reservoirs (<8,000 feet) and short to mid-range laterals (1.0 mile and 1.5 mile, respectively) allow for efficient full-scale development without the requirement for extended reach laterals and large fracs to meet economic thresholds.

From shallow conventional reservoirs to deeper sand and shale plays across the Rockies, we have stacked pay that offers attractive returns and efficient full-scale development opportunities across our portfolio.

We have assembled a management team at our Company with extensive experience in the fields of business development, petroleum engineering, geology, field development and production, operations, planning and corporate finance.

Our management team is headed by J.

Douglas Schick, who has served as our President since 2018 and was recently appointed as our Chief Executive Officer effective January 1, 2025, and has over 25 years of experience in the oil and gas industry, having co-founded American Resources, Inc., and formerly serving in executive, management and operational planning, strategy and finance roles at Highland Oil and Gas, Mariner Energy, Inc., The Houston Exploration Co., ConocoPhillips and Shell Oil Company.

Douglas Schick, who has served as our President since 2018 and as our Chief Executive Officer since January 2025 and also serves as a member of our Board of Directors, and has over 25 years of experience in the oil and gas industry, having co-founded American Resources, Inc., and formerly serving in executive, management and operational planning, strategy and finance roles at Highland Oil and Gas, Mariner Energy, Inc., The Houston Exploration Co., ConocoPhillips and Shell Oil Company.

Additionally, our Chief Commercial Officer, Jody D.

Crook, has over 25 years of experience in the oil and gas industry, having co-founded oil and gas consulting and operational firms Tenet Advisory Group LLC and Bronze Four Resources, LLC, and formerly serving in various leadership roles and positions of increasing responsibility at Jones Energy, Ltd., Southwestern Energy, and Enron Corp.

In addition, Reagan Tuck (R.T.) Dukes, who was appointed as our Chief Operating Officer effective October 31, 2025, has nearly 20 years of experience in the oil and gas industry, with extensive experience in oil and gas investing, finance, research, and consulting, having formerly served as the chief financial officer and as the chief executive officer of Century Natural Resources, LLC, as a research director and director of North American supply at Wood Mckenzie Limited, and as a manager at KED Interests, LLC.

Furthermore, Robert “Bobby” Long, who was appointed as our Chief Financial Officer effective October 31, 2025, has nearly 25 years of financial experience in management, corporate finance, and principal investing in the energy industry, having formerly served as the chief financial officer of Century Natural Resources, LLC, as the chief financial officer of Navigation Petroleum, as an executive director of CIBC Capital Markets, as a partner in Rivington Holdings, LLC, as an associate, and then vice president, of BNP Paribas, Global Energy Group, and as an analyst at JP Morgan Chase & Co., Energy Finance.

Also, our Executive Vice President and General Counsel, Clark R.

Moore, has nearly 20 years of energy industry experience, and formerly served as acting general counsel of Erin Energy Corp.

Moore, has 20 years of energy industry experience, and formerly served as acting general counsel of Erin Energy Corp.

All members of the management and operations teams have also successfully helped develop and build similar exploration and production companies with like kind asset profiles and technical operations in multiple oil and gas producing basins in the United States.

We believe that our management team is highly qualified to identify, acquire and exploit energy resources in the U.S.

Our Board of Directors also brings extensive oil and gas industry experience, headed by our Executive Chairman, Dr.

Kukes, who brings over 40 years of experience in the oil industry, serving as our Chief Executive Officer from 2018 through 2024, and formerly serving as the CEO at Samara-Nafta, a joint venture with the U.S.-based international oil company Hess Corporation, CEO of Tyumen Oil Company (TNK), prior to its combination with British Petroleum, and as Chairman of Yukos Oil Company.

In addition, our Board includes John J.

Scelfo, who brings over 40 years of experience in oil and gas management, finance and accounting, and who served in numerous executive-level capacities at Hess Corporation, including as Senior Vice President, Finance and Corporate Development, Chief Financial Officer, Worldwide Exploration & Producing, and as a member of Hess’ Executive Committee.

Our Board also includes H.

Douglas Evans, who brings over 50 years of experience in executive management positions with Gulf Interstate Engineering Company, one of the world's top pipeline design and engineering firms, including as its Honorary Chairman and previously its Chairman and President and Chief Executive Officer, and who is a past President and Board member of the International Pipe Line and Offshore Contractors Association, former Chairman of its Strategy Committee, and formerly a member of the Pipeline Contractors Association.

Our Board of Directors also brings extensive oil and gas industry experience, headed by our Chairman, Josh Schmidt, who brings over 15 years of experience in the energy industry, currently serving as a partner, chief operating officer and member of the investment committee of Juniper, and previously having worked at Citigroup Energy in Houston, Texas, as a natural gas and electricity trader.

Our Board also includes Edward Geiser, the founder and Executive Managing Partner of Juniper and head of its investment committee, who previously served as a managing director at Och-Ziff, and in the investment banking groups of both Merrill Lynch and Morgan Stanley.

In addition, our Board includes John Howie, who has over 40 years of experience in oil and gas engineering, management, and finance, formerly serving as president of Tellurian Production Company, founder and manager of Impact Natural Resources and Parallel Resource Partners, as Head of E&P Global Capital at Goldman, Sachs and Company, as vice president of EnCap Investments, L.L.C., and at various other E&P companies, including Range Resources Corporation, Apache Corporation, and Amoco Corporation.

Our Board also includes Martyn Willsher, currently chief executive officer of Unified Petroleum LLC, who formerly served as chief executive officer, senior vice president, and chief financial officer of Amplify Energy Corp., and held various management roles at Memorial Production Partners GP, LLC and Constellation Energy, and served in various business development and financial analysis roles at JM Huber Corp., FTI Consulting and PricewaterhouseCoopers LLP.

Our Board also includes Kristel Franklin, who brings deep expertise spanning integrated upstream and midstream operations with over 20 years of experience in the oil and gas industry, currently serving as chief operating officer of PureWest Energy, and previously leading Moontower Resources, LLC to a successful exit for Oaktree Capital, and serving in various roles of increasing responsibility at Three-Rivers Operating Company III and Jones Energy, and at Exxon Mobil Corporation as a Senior Drilling Engineer.

Significant acreage positions and drilling potential .

As of December 31, 2024, we have accumulated interests in a total of 14,105 net acres in our core Permian Basin Asset operating area, and 18,669 net acres in our core D-J Basin Asset operating area, both of which we believe represent significant upside potential.

As of December 31, 2025, we have accumulated interests in a total of 99,561 net acres in our core D-J Basin Asset operating area, 201,886 net acres in our core Powder River Basin Asset operating area, and 14,105 net acres in our core Permian Basin Asset operating area, all of which we believe represent significant upside potential.

The majority of our interests are in or near areas of considerable activity by both major and independent operators, although such activity may not be indicative of our future operations.

Based on our current acreage position, we believe our Permian Basin Asset could contain up to 100 potential net 1.0 mile laterals wells on 160 acre spacing.

We believe our D-J Basin Asset could contain up to 353 potential gross wells with 164 potential net wells, comprised of two gross 1.0-mile lateral wells with one net 1.0-mile lateral well, 351 gross 2.0-mile lateral wells with 163 net 2.0 mile lateral wells, on 80-acre spacing and 160-acre spacing, respectively, providing us with a substantial drilling inventory for future years.

Not all of these potential well locations in our Permian Basin Asset and D-J Basin Asset are included in our reserve report due to SEC guidelines related to development timing.

We generally sell a significant portion of our oil and gas production to a relatively small number of customers, and during the year ended December 31, 2024, sales to three customers comprised 38%, 36% and 12%, respectively, of the Company’s total oil and gas revenues.

Based on our current acreage position, we believe our D-J Basin Asset could contain up to 450 potential gross well locations of varying lateral lengths.

We believe our Powder River Basin Asset could contain up to 455 potential gross well locations of varying lateral lengths.

We also believe our Permian Basin Asset could contain up to 155 potential gross 1.0 mile lateral locations.

Combined our asset base could contain over 1,000 gross locations of varying lateral lengths providing years of potential inventory.

Not all of these potential well locations in our D-J Basin Asset, Powder River Basin and Permian Basin Asset are included in our reserve report due to SEC guidelines related to development timing.

We generally sell a significant portion of our oil and gas production to a relatively small number of customers, and during the year ended December 31, 2025, sales to two customers comprised 26% and 22%, respectively, of the Company’s total oil and gas revenues.

No other customer accounted for more than 10% of our revenue during these periods.

The Company is not dependent upon any one purchaser and believes that, if its primary customers are unable or unwilling to continue to purchase the Company’s production, there are a substantial number of alternative buyers for its production at comparable prices.

For properties in which we are a non-operator, we are highly dependent on the success of our third-party operators and the decisions made in connection with their operations.

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 December 31, 2025, one individual operator accounted for more than 10% of our total production revenues, representing approximately 30% of our total production sales for the year.

Our crude oil is generally sold under short-term, extendable and cancellable agreements with unaffiliated purchasers.

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Natural Gas .

Our natural gas is predominately sold under short-term natural gas purchase agreements, with one gas purchase agreement for our D-J Basin Asset that is in effect until April 1, 2032.

However, natural gas sales related to this agreement only represent less than 1% of our total revenues as of December 31, 2024, and the Company believes that this trend will continue in the D-J Basin Asset.

Our natural gas is predominately sold under short-term natural gas purchase agreements, with one gas purchase agreement.

Natural gas produced by us is sold at various delivery points at or near producing wells to both unaffiliated independent marketing companies and unaffiliated mid-stream companies.

We receive proceeds from prices that are based on various pipeline indices less any associated fees for processing, location or transportation differentials.

Following the Mergers, the Acquired Companies continue to maintain agreements with various midstream providers for the gathering, processing and marketing of their oil and gas production, including long-term arrangements with Roaring Fork Midstream, LLC (“ RFM ”) covering a majority of production in Laramie County, Wyoming, which extend beyond 2030 and do not include minimum volume commitments.

Although Juniper Capital Advisors, L.P.

previously controlled RFM and retains a minority equity interest, the agreements are on arm’s-length terms.

Additional crude volumes are gathered or sold through three separate, non-affiliated companies at prevailing market prices subject to customary marketing and transportation deductions.

Oil and Gas Properties

We believe that our Permian Basin and D-J Basin assets represent among the most economic oil and natural gas plays in the U.S.

We plan to opportunistically seek additional acreage proximate to our currently held core acreage located in the Northwest Shelf of the Permian Basin in Chaves and Roosevelt Counties, New Mexico, and the Wattenberg and Wattenberg Extension areas of Weld and Morgan Counties, Colorado, and Laramie County, Wyoming, and elsewhere in the D-J Basin.

We believe that our D-J Basin, PRB, and Permian Basin Assets represent among the most economic oil and natural gas plays in the U.S.

We plan to opportunistically seek additional acreage proximate to our currently held core acreage located in the Wattenberg and Wattenberg Extension areas of Weld and Morgan Counties, Colorado, and Laramie County, Wyoming, and elsewhere in the D-J Basin, the PRB, and the Northwest Shelf of the Permian Basin in Chaves and Roosevelt Counties, New Mexico.

Our net capital expenditures for 2025 are estimated at the time of this Annual Report to range between $27 million to $33 million.

We anticipate that approximately 70% to 75% of our expected capital expenditures for 2025 will be allocated to development in the D-J Basin under our February 2025 joint development agreement entered into with a large private equity-backed D-J Basin operator and our Participation Agreement and (AMI) entered into in August 2024 with a private operator.

This estimate does not include expenditures for acquisitions or other projects that may arise but are not currently anticipated.

Risk Factors ”).

Our strategy in the PRB and the Permian Basin is to be the operator and/or a significant working interest owner, directly or through our subsidiaries and joint ventures, in the majority of our acreage so we can dictate the pace of development in order to execute our business plan.

Our Core Areas

D-J Basin Asset

We hold our combined D-J Basin Asset through our wholly-owned subsidiaries PRH Holdings LLC (PRH), and North Peak Oil & Gas, LLC (NPOG) an additional wholly-owned subsidiary acquired through the Mergers.

Operations are conducted through our wholly-owned operating subsidiaries, including Red Hawk Oil & Gas, LLC (“Red Hawk”), Longs Peak Resources, LLC (LPR), and North Silo Resources, LLC (NSR).

Our D-J Basin Asset was assembled through our legacy operations and expanded significantly through the Mergers which, as discussed above, closed on October 31, 2025.

Prior to the Mergers, we had grown our legacy D-J Basin position to approximately 15,853 net acres in Weld and Morgan Counties, Colorado, and approximately 4,823 net acres in Laramie County, Wyoming.

Through the Merger, we acquired additional substantial D-J Basin interests held by the Acquired Companies, with 72,022 net acres being located in Laramie County, Wyoming, and an additional 6,863 net acres located in Weld County, Colorado, making Wyoming the location of a majority of our combined D-J Basin net acreage.

As of December 31, 2025, our combined D-J Basin Asset consisted of 99,561 net leasehold acres, of which approximately 22,716 net acres are located in Colorado and approximately 76,845 net acres are located in Wyoming.

More than 88% of our net D-J Basin acreage is located on private lands.

As of December 31, 2025, approximately 70% of our net D-J Basin acres are held by production (“HBP”), and we hold an average working interest of approximately 92% across our operated net D-J Basin acreage (inclusive of our net royalty acres).

Our D-J Basin Asset acreage is located in the areas shown in the map below.

We serve as operator of 74 gross (66.9 net) wells in our D-J Basin Asset, and we participate as a non-operated working interest owner in an additional 110 gross (12.5 net) wells, for a combined total of 184 gross (79.4 net) wells as of December 31, 2025.

The D-J Basin is one of the most prolific oil and natural gas producing basins in the United States, extending from northern Colorado into southeastern Wyoming and western Nebraska.

Our operated D-J Basin program is focused primarily on horizontal wells targeting the Codell sandstone formation, a Lower Cretaceous siliceous sandstone that has demonstrated strong well productivity across our operated acreage in southeastern Wyoming.

Our non-operated working interest participations are concentrated in horizontal wells targeting the Niobrara formation, which consists of multiple productive carbonate benches commonly referred to as the “A,” “B,” and “C” benches, and which is the primary development target for many of the leading operators active in the D-J Basin.

The Wattenberg and Wattenberg Extension areas of northern Colorado and the Wyoming D-J Basin Extension have experienced a sustained and significant increase in horizontal drilling activity since 2018, driven by continued advances in completion design, including extended lateral lengths, increased proppant loading, additional frac stages, and improved stage spacing, that have materially improved well productivity and capital efficiency across both formations.

Wyoming is recognized as one of the most oil and gas operator-friendly regulatory environments in the United States.

Our D-J Basin operations in Wyoming are subject to oversight by the Wyoming Oil and Gas Conservation Commission (“WOGCC”), and our Colorado D-J Basin operations are subject to oversight by the Colorado Energy & Carbon Management Commission (“ECMC”).

We actively pursue operatorship across our acreage position where our leasehold ownership and surface configuration permit us to do so.

Our D-J Basin acreage is concentrated in areas proximate to leading public and private operators with active and growing Niobrara and Codell development programs.

Our non-operated working interest participations benefit from the continued Niobrara-focused horizontal development programs of notable operators including Chevron Corporation (which acquired Noble Energy in October 2020 and PDC Energy in August 2023), SM Energy Company (which merged with Civitas Resources, Inc.

in January 2026, with SM Energy as the surviving entity), EOG Resources, Inc., Occidental Petroleum Corporation, Bison Oil & Gas IV, and Peoria Resources, LLC (a U.S.

subsidiary of Japan Petroleum Exploration Co., Ltd.

(“JAPEX”), which completed the acquisition of Verdad Resources LLC’s operated D-J Basin portfolio in February 2026), among others.

Continued development by these offset and partner operators provides ongoing geological delineation and production data that further support our understanding of the economic potential of our acreage across both our operated and non-operated positions.

Our primary operated D-J Basin development program targets the Codell sandstone formation with horizontal wells on our Wyoming acreage, where we serve as operator and control the pace of development.

In our non-operated D-J Basin acreage, our strategy is to participate in Niobrara-focused horizontal development projects operated by leading public and private E&P companies that we deem highly economic based on well-level returns and capital efficiency.

We are actively enhancing our D-J Basin land position through organic leasing, pooling, acreage swaps, bolt-on acquisitions, and the pursuit of additional operatorship opportunities similar to the recently completed Mergers.

Post closing of the Mergers, we implemented a maintenance capital program focused on optimization projects on our producing wells, including well cleanouts, compression optimization, and artificial lift conversions, which we expect to meaningfully lower our lease operating expenses on a per-unit basis.

We believe our combined D-J Basin Asset provides significant near-term development opportunities, with hundreds of potential drilling locations across both the Codell and Niobrara formations that are immediately adjacent to our existing producing wells.

Powder River Basin Asset

We hold our Powder River Basin Asset (our “PRB Asset”) through Century Oil & Gas Sub-Holdings, LLC, our wholly-owned subsidiary acquired through the Mergers, with operations conducted through Century Oil & Gas, LLC, Navigation Powder River, LLC, and Pine Haven Resources, LLC.

Our PRB Asset was acquired in its entirety through the Mergers and represents a large-scale, multi-horizon resource opportunity in northeastern Wyoming.

Our PRB Asset interests are primarily located in Johnson, Campbell, Converse, Weston, and Niobrara Counties in northeastern Wyoming.

As of December 31, 2025, our PRB Asset consisted of 201,886 net leasehold acres.

More than 89% of our net PRB acreage is located on federal lands administered by the Bureau of Land Management (“BLM”).

As of December 31, 2025, approximately 53,222 of our net PRB acres are held by production, with the remainder held primarily by production payment (suspense) or on primary term.

We hold an average working interest of approximately 76% on our operated net PRB acreage (including our net royalty acres).

Our PRB Asset acreage is located in the areas shown on the map below.

We serve as operator of 140 gross (134.1 net) wells in our PRB Asset, and we participate as a non-operated working interest owner in an additional 16 gross (1.4 net) wells, for a combined total of 156 gross (135.4 net) wells as of December 31, 2025.

The Powder River Basin is one of the most significant sedimentary basins in the Rocky Mountain region, characterized by a thick Cretaceous-age stratigraphic column with numerous stacked pay zones that provide extensive development optionality.

Our PRB Asset targets a broad range of productive formations spanning both the Upper and Lower Cretaceous sections.

Upper Cretaceous targets include the Teapot, Parkman, Sussex, and Shannon, while Lower Cretaceous and transitional targets include the Niobrara, Turner, Frontier, Mowry, and Muddy formations.

We believe that this extensive stacked pay column, spanning thousands of feet, provides significant future development optionality for the Company across a broad range of commodity price environments and capital allocation strategies.

Within our PRB acreage position, we have identified significant multi-formation development potential supported by active offset operator drilling activity across multiple horizons proximate to our acreage.

Of particular note are the Parkman, Sussex, Niobrara, Turner, and Mowry formations, each of which has been subject to meaningful offset operator activity in areas adjacent to our acreage, providing ongoing geological and production data that in our opinion further supports the economic potential of these horizons across our position.

We believe the breadth of active development across these stacked formations, combined with our concentrated acreage footprint in Johnson, Campbell, Weston, and Niobrara Counties, provides us with a compelling multi-formation development inventory and the flexibility to allocate capital to the highest-return opportunities as the basin continues to mature.

Given that a substantial majority of our PRB acreage is located on federal lands, our PRB operations are subject to regulatory oversight by both the BLM and the WOGCC.

We work closely with these agencies with respect to permitting, right-of-way acquisition, development planning, and compliance obligations for our PRB operations.

Wyoming’s demonstrated commitment to a stable and predictable regulatory environment for oil and gas development, including permitting timelines and operational flexibility on federal lands, makes our PRB position particularly well-suited for long-term capital allocation.

Historical development activity on our PRB acreage has been focused primarily in the Central area of our position.

More recently, both the North and West portions of our PRB acreage have seen a meaningful increase in offset operator activity, particularly in the Niobrara, Turner, Parkman, Sussex, and Mowry formations, which we believe will continue to delineate productivity and further support the economics of future development on our acreage.

Notable operators active in the vicinity of our PRB acreage include Anschutz Exploration Corporation, Continental Resources, Inc., Devon Energy Corporation, EOG Resources, Occidental Petroleum Corporation, and various other large private operators, among others.

We believe our large and concentrated PRB acreage position provides us with the potential for years of development optionality and the ability to allocate capital efficiently as commodity markets and offset operator activity continue to evolve.

We evaluate future PRB development opportunities on an ongoing basis, with a focus on projects that generate strong risk-adjusted returns.

Permian Basin Asset

We hold our Permian Basin Asset through our wholly-owned subsidiary, PEDCO, with operations conducted through PEDCO’s wholly-owned operating subsidiary, RAZO.

We hold our Permian Basin Asset through our wholly-owned subsidiary, PEDCO, with operations conducted through PEDCO’s wholly-owned operating subsidiary, Ridgeway Arizona Oil Corp.

Our Permian Basin Asset was assembled through three acquisitions completed between 2018 and 2019.

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In 2019, we acquired additional assets in two bolt-on acquisitions from private operators, and in November 2023 we divested approximately 8,035 gross leasehold acres and related wells in the non-core Milnesand and Sawyer Fields of our Permian Basin Asset to a private operator in order to reduce our asset retirement obligations and plugging and abandoning liabilities with respect to these non-core assets, thereby eliminating approximately $3.2 million in plugging and abandonment liabilities and freeing up our resources to allow us to better focus on development of our other assets.

Our current Permian Basin Asset interests are all located in Chaves and Roosevelt Counties, New Mexico, where we currently operate 35 gross (33.5 net) wells, of which 28 wells are active producers, and two are active SWDs.

As of December 31, 2025, our Permian Basin Asset acreage is located where indicated in the below map of the State of New Mexico and more specifically in the areas shaded in yellow in the subsequent sectional map.

State of New Mexico

In September 2023, the Company and Evolution Petroleum Corporation (“ Evolution ”) entered into a Participation Agreement (the “ Participation Agreement ”) for the joint development of a portion of the Company’s Permian Basin Asset known as the Chaveroo oilfield, located in Chaves and Roosevelt Counties, New Mexico (the “ Chaveroo Field ” and the “ Chaveroo Farmout Transaction ”).

Pursuant to the Participation Agreement, the Company and Evolution identified twelve “Development Blocks” covering approximately 16,000 gross leasehold acres consisting of all leasehold rights from the surface to the base of the San Andres formation, where the Company currently holds leasehold interests (“ Existing Leases ”), in which the parties may jointly develop by drilling and completion of up to nine horizontal San Andres wells in each Development Block in accordance with the terms of the agreement, which terms include, but are not limited to:

(i) Evolution made an initial payment of $366,000 to the Company in exchange for a 50% working interest share in the Existing Leases, covering the initial two Development Blocks (which equals Evolution’s share of the acreage portion for nine drilling locations therein);

(ii) upon completion of the wells in each Development Block, Evolution will have the right, but not the obligation, to acquire a 50% working interest share in the next Development Block in exchange for the payment of $450 per net acre of Existing Leases held by the Company in such block, and participate on a 50% working interest share basis in the drilling and completion of up to nine horizontal San Andres wells in such Development Block;

(iii) the parties entered into a standard operating agreement with the Company serving as the operator with respect to the development of the assets;

(iv) if either party elects not to participate in the development of a Development Block, the other party may develop such Development Block independently with the non-participating party not required to participate in the same;

(v) the creation of an area of mutual interest by the parties comprised of lands in the Chaveroo Field;

and (vi) certain other terms and conditions standard in such participation agreements.

The Participation Agreement has an initial term expiring on December 31, 2025, but continues in full force and effect for so long as the parties continue to develop the Development Blocks in accordance with the terms of the agreement.

The Participation Agreement includes customary representations and warranties of the parties and also provides that any new leases acquired by the Company within certain identified tracts within two years from the date of the agreement will become Existing Leases under the agreement.

Pursuant to the Participation Agreement, in September 2023 Evolution acquired a 50% working interest share in Existing Leases covering approximately 813 net acres located in the first and second Development Blocks in exchange for the payment of $366,000 in total proceeds to the Company, and in June 2024 Evolution acquired a 50% working interest share in Existing Leases covering approximately 811 net acres located in the third, fourth and fifth Development Blocks in exchange for the payment of $365,000 in total proceeds to the Company.

In addition, in December 2023, the Company’s operator, RAZO, entered into a Stipulated Final Order (“ SFO ”) with the Director of the Oil and Gas Conservation Division of New Mexico (the “ OCD ”) pursuant to which, among other things, RAZO agreed to reimburse the OCD for actual costs incurred by the OCD for plugging and abandoning approximately 299 inactive legacy wells in the Permian Basin Asset at a rate of $2.00 per gross barrel of oil sold by RAZO during any production reporting period, subject to a minimum payment of $30,000 per month by RAZO.

In September 2023, the Company and Evolution Petroleum Corporation (“Evolution”) entered into a Participation Agreement for the joint development of the Chaveroo oilfield in Chaves and Roosevelt Counties, New Mexico.

The agreement covers twelve Development Blocks encompassing approximately 16,000 gross leasehold acres, within which the parties may jointly drill up to nine horizontal San Andres wells per block on a 50/50 working interest basis, with the Company serving as operator.

Evolution's entry into each successive Development Block is optional, at a cost of approximately $450 per net acre, and either party may independently develop any block the other elects to skip.

The agreement continues in effect for so long as the parties proceed with development, and new leases acquired by the Company within certain identified tracts within two years of signing are included as existing leases.

To date,Evolution has acquired working interests in five Development Blocks:

a 50% interest in approximately 813 net acres in the first and second Development Blocks for $366,000 in September 2023;

a 50% interest in approximately 811 net acres in the third, fourth, and fifth Development Blocks for $365,000 in June 2024;

and a 50% interest in approximately 640 net acres in the eighth Development Block for $288,000 in September 2025.

In addition, in December 2023, the Company’s operating company, RAZO, entered into a Stipulated Final Order (“SFO”) with the Director of the Oil and Gas Conservation Division of New Mexico (the “OCD”) pursuant to which, among other things, RAZO agreed to reimburse the OCD for actual costs incurred by the OCD for plugging and abandoning approximately 299 inactive legacy wells in the Permian Basin Asset at a rate of $2.00 per gross barrel of oil sold by RAZO during any production reporting period, subject to a minimum payment of $30,000 per month by RAZO.

RAZO has been timely paying each reimbursement invoice received from the OCD in accordance with the SFO and is in full compliance with the SFO.

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D-J Basin Asset

We have grown our legacy D-J Basin Asset position to approximately 14,809 net acres in Weld and Morgan Counties, Colorado and approximately 3,860 net acres in Laramie County, Wyoming.

We directly hold all of our interests in the D-J Basin Asset through our wholly-owned subsidiary, PRH.

These interests are all located in Weld and Morgan Counties, Colorado and Laramie County, Wyoming.

PRH has an interest in 82 gross (21.9 net) wells and our wholly-owned operating subsidiary, Red Hawk, is currently the operator of 17 gross (15.4 net) wells located in our D-J Basin Asset.

Our D-J Basin Asset acreage is located in the areas shown in the map below.

The D-J Basin’s Wattenberg Extension has seen a tremendous amount of growth in drilling activity since 2018 due to enhanced completions design and interest in the area as a result of its remote location away from more populated areas of the Wattenberg play to the south.

D-J Basin operators are drilling horizontal wells in the Niobrara formation in several Niobrara benches and in the Codell formation, utilizing the latest advances in completion design, frac stages, and frac intensity to obtain favorable well results.

Notable non-operated partners leading the Niobrara revival are Chevron Corporation (which acquired Noble Energy in October 2020 and PDC Energy in August 2023), Civitas Resources, Inc.

(formed by the merger of Bonanza Creek Energy and Extraction Oil and Gas in November 2021) and several large private equity-backed independent E&P companies like Bison Oil & Gas IV and Verdad Resources LLC.

Other active operators in the area include Fundare Resources Company, LLC (which acquired Whiting Petroleum Company’s D-J Basin interests in late 2019), and Occidental Petroleum (which acquired Anadarko Petroleum in 2019).

Weld and Morgan Counties, Colorado and Laramie County, Wyoming

Production, Sales Price and Production Costs

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Excludes workover costs, marketing, ad valorem, severance taxes and ARO Settlements.

As of December 31, 2024, the Wattenberg Field in our D-J Basin Asset and as of December 31, 2023 and 2022, the Chaveroo Field in our Permian Basin Asset and the Wattenberg Field in our D-J Basin Asset are the fields that each comprise 15% or more of our total proved reserves.

As of December 31, 2025, the Wattenberg Field and the D-J Wyoming Field in our D-J Basin Asset, and as of December 31, 2024 the Wattenberg Field in our D-J Basin, and as of December 31, 2023, the Chaveroo Field in our Permian Basin Asset and the Wattenberg Field in our D-J Basin Asset are the fields that each comprise 15% or more of our total proved reserves.

The applicable production volumes from these fields for the years ended December 31, 2025, 2024, and 2023, are represented in the table below in total barrels (Bbls):

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Wattenberg (D-J Asset Base)

The following table summarizes our gross and net developed and undeveloped leasehold acreage Iat December 31, 2024:

D-J Wyoming (D-J Asset Base)

Natural Gas (Mcf):

Chaveroo (Permian Asset Base)

Wattenberg (D-J Asset Base)

D-J Wyoming (D-J Asset Base)

Chaveroo (Permian Asset Base)

Wattenberg (D-J Asset Base)

D-J Wyoming (D-J Asset Base)

Total Production (Boe)(1):

Chaveroo (Permian Asset Base)

Wattenberg (D-J Asset Base)

D-J Wyoming (D-J Asset Base)

Assumes 6 Mcf of natural gas equivalents to 1 barrel of oil.

The following table summarizes our gross and net developed and undeveloped leasehold acreage at December 31, 2025:

Developed (1)

Undeveloped (2)

Powder River Basin

Permian Basin

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(i) in the D-J Basin Asset, 16,138 net acres are set to expire during 2026 (net to our direct ownership interest only), with 2,110 and 678 net acres set to expire for the years ending December 31, 2027 and 2028 respectively, and 8,081 net acres thereafter;

and (ii) in the Permian Basin Asset only 200 net acres are set to expire for the year ending December 31, 2026, (net to our direct ownership interest only), with all of the remaining acreage currently held by production.

We expect to retain substantially all of our expiring acreage either through drilling activities, renewal of the expiring leases or through the exercise of extension options.

(ii) in the Permian Basin Asset only 200 net acres are set to expire for the year ending December 31, 2026;

and (iii) in the Powder River Basin Asset, 4,822 net acres are set to expire during 2026, with 34,999 and 15,828 net acres set to expire for the years ending December 31, 2027 and 2028, respectively (net to our direct ownership interest only), with all of the remaining acreage currently held by production.

The following table presents our ownership in productive crude oil and natural gas wells at December 31, 2025.

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We drilled wells or participated in the drilling of wells as indicated in the table below:

The following table sets forth information about wells for which drilling was in progress or which were drilled but uncompleted at December 31, 2025, which are not included in the above table:

Drilling In Progress

Drilled But Uncompleted

Development wells

Exploratory wells

Oil and Natural Gas Reserves

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A copy of the report issued by Cawley, Gillespie & Associates, Inc.

is attached to this Report as Exhibit 99.1 .

is incorporated by reference as Exhibit 99.1 to this Report.

For more information regarding our oil and gas reserves, please refer to “ Item 8 Financial Statements and Supplementary Data ” – “Supplemental Oil and Gas Disclosures (Unaudited) ”.

Current Year Events

Participations Agreements Related to D-J Basin Assets

Additionally, to facilitate joint development of the SW Pony Prospect, the parties agreed to an approximately 16,900 gross acre Area of Mutual Interest wherein the Joint Development Party will transfer 30% of future interests acquired by the Joint Development Party in leaseholds to PRH, and PRH will transfer 70% of future interests acquired by PRH in leaseholds to the Joint Development Party, in each case at an acquisition cost proportionate to their respective interests.

The assigned interests will be subject to an overriding royalty, such that the assigning party shall deliver to the other party leasehold interests with an 80% net revenue interest, and the parties agreed that the Joint Development Party will be the operator of the combined leaseholds.

The Participation Agreement specifically addresses the Harlequin Wells, which are existing wells within the SW Pony Prospect, whereby PRH acquired a 30% undivided interest in six Harlequin Wells as part of the leasehold assignment.

The Company correspondingly paid $8.6 million in capital costs related to these wells.

In February 2025, the Company entered into a joint development agreement (“ Agreement ”) with a large, Denver, Colorado-based private equity-backed D-J Basin E&P Company with extensive operational experience (“ Operator ”), pursuant to which the parties agreed to jointly participate in the expansion and development of the Company’s Roth and Amber DSUs located in Weld County, Colorado, with the Operator paying to the Company $1.7 million, the Company agreeing to amend the Company’s existing Roth and Amber DSUs to increase each to 1,600 acres and transferring operatorship of the DSUs to the Operator, and the parties agreeing to jointly participate in the development of the Roth and Amber DSUs.

Sale of Non-Core D-J Basin Assets

On September 23, 2024, PRH sold 320 net acres to a third-party in the Company’s D-J Basin Asset for $750,000, and, with the Company recognizing a $735,000 gain from the sale of oil and gas properties.

Merger Agreement

On October 31, 2025, the Company closed the transactions contemplated by an Agreement and Plan of Merger dated October 31, 2025, by and among the Company;

NP Merger Sub, LLC and COG Merger Sub, LLC, each a wholly owned subsidiary of the Company;

and, solely for specified purposes therein, North Peak Oil & Gas Holdings, LLC.

Pursuant to the Merger Agreement, (i) NP Merger Sub, LLC merged with and into NPOG, with NPOG surviving as a wholly owned subsidiary of the Company, and (ii) COG Merger Sub, LLC merged with and into COG, with COG surviving as a wholly owned subsidiary of the Company.

Highlights of the Company following the Mergers:

The Mergers position the Company as a premier publicly traded Rockies-focused operator with an expanded footprint of approximately 320,000 net acres across the D-J Basin and the PRB.

The transaction significantly increases the Company’s oil-weighted production and enhances its scale in these core operating areas.

The Company generates strong cash flow supported by its relatively high oil production mix and competitive cost structure.

Its substantial acreage position in the D-J Basin and Powder River Basin, which includes multiple productive formations, provides more than a decade of identified drilling inventory based on current development plans.

The Company maintains a low-cost operating profile characterized by disciplined general and administrative expenses and a conservative capital structure, which management expects to preserve going forward.

The Company believes that it is positioned for organic production growth, with 32 wells (with varying working interests) recently completed in the fourth quarter of 2025 and early first quarter of 2026.

These wells are expected to drive near-term production increases.

In addition, the Company intends to pursue strategic consolidation opportunities within its core areas of focus, targeting acquisitions that are expected to be accretive and generate operational synergies, while maintaining balance sheet strength.

Drilling and Completion, Leasing, and Mineral Lease Acquisition Activities

For the year ended December 31, 2024, the Company incurred $20.5 million of capital costs.

These costs were primarily related to non-operated drilling and completion costs related to the Company’s participation in 24 new non-operated wells in the D-J Basin in which the Company participated and the Company’s completion operations with respect to three operated wells with a third-party in the Permian Basin, together with costs related to certain workovers for lift conversions, cleanouts and permitting in the Company’s D-J Basin Asset.

The Company also acquired approximately 267 net mineral acres and 4,960 net lease acres in and around its existing footprint in the D-J Basin through multiple transactions at total acquisition and due diligence costs of $725,000 and $862,000, respectively.

Reserve-Based Lending Facility

On September 11, 2024, the Company entered into a new $250 million reserve-based lending facility (the “ RBL ” or “ Facility ”) with Citibank, N.A., as administrative agent, and the lenders (including Citibank, N.A.) from time to time a party thereto.

The Facility has a maturity of four years and provides for an initial borrowing base of $20.0 million and an aggregate maximum revolving credit amount of $250 million.

The Company has not drawn down any borrowings under the Facility as of the date of these financial statements.

The RBL includes customary representations and warranties, and affirmative and negative covenants of the Company for a facility of that size and type, including prohibiting the Loan Parties from creating any indebtedness without the consent of the lenders, subject to certain exceptions, and requiring the Company to have a net leverage ratio (the ratio of (a) total net debt to (b) EBITDAX) of no less than 1.0 to 1.0 and a current ratio (the ratio of (i) consolidated current assets to (ii) consolidated current liabilities) of no less than 1.0 to 1.0.

EBITDAX is defined as Earnings Before Interest, Taxes, Depreciation (or Depletion), Amortization, and Exploration Expense.

Milnesand Sale Dispute and Tilloo Note Default

On November 4, 2024 the Company received correspondence from legal counsel to Tilloo Exploration & Production, LLC (“ Tilloo ”) seeking to recover damages which Tilloo is alleging were caused by alleged intentional misrepresentations made by principals of the Company to principals of Tilloo in connection with Tilloo’s acquisition of the Milnesand and Sawyer fields in New Mexico from the Company for aggregate consideration of $1,122,436 effective August 1, 2023 (the “ Milnesand Sale ”), which consideration was paid to the Company by Tilloo via a five-year secured promissory note with 10% annual interest and no payments due until January 8, 2025 (the “ Tilloo Note ”).

The Company does not believe any misrepresentations were made by the Company or its principals in the Milnesand Sale and that the claims are baseless, without merit, and fail as a matter of law.

The Company has not received any correspondence from Tilloo subsequent to receipt of the November 4, 2024 correspondence from Tilloo, and Tilloo failed to make the initial installment payment due under the Tilloo Note on January 8, 2025.

The Company issued a notice of default under the Tilloo Note to Tilloo in mid-January 2025, and the Company intends to pursue all available avenues and remedies, including potential foreclosure under the security agreement and mortgages securing the secured obligation, to resolve these matters.

For the year ended December 31, 2025, the Company incurred $239.2 million of capital additions of which $204.6 million were related to the Mergers (noted above) and $34.0 million of capital costs were primarily related to the Company’s completion operations with respect to four operated wells, drilled and completed with a third-party, as well as five lift conversions in the Permian Basin.

The Company also participated in the drilling and completion of 23 non-operated wells in the D-J Basin for which production had begun in late 2025, with the Company working interest holdings in these wells ranging from 8% to 44%.

Additionally, the Company acquired approximately 100 net mineral acres and 310 net lease acres in and around its existing footprint in the D-J Basin through multiple transactions at total acquisition and due diligence costs of $194,000 and $420,000, respectively.

Amended and Restated A&R Credit Agreement

On October 31, 2025, the Company entered into an Amended and Restated Credit Agreement, which amended and restated its prior senior secured revolving credit agreement dated September 11, 2024, with Citibank, N.A., as administrative agent, and the lenders party thereto.

The A&R Credit Agreement matures on October 31, 2029 and provides for an initial borrowing base and elected commitments of $120 million, with a maximum revolving commitment of $250 million.

The borrowing base is subject to scheduled semiannual redeterminations beginning December 1, 2025, as well as unscheduled redeterminations and other adjustments, and is determined by the lenders in their discretion.

Borrowings are subject to customary conditions, including compliance with financial covenants.

The A&R Credit Agreement includes customary representations and warranties for a facility of that size and type, including prohibiting the Loan Parties from creating any indebtedness without the consent of the lenders, subject to certain exceptions.

In connection with the closing of the Mergers, the Company borrowed $87 million under the A&R Credit Agreement, with additional borrowings of $6 million on January 8, 2026 and $5 million on February 5, 2026.

Issuance and Automatic Conversion of Series A Convertible Preferred Stock

As part of the Mergers (noted above), the Company issued Series A Convertible Preferred Stock in two transactions.

First, 10,650,000 shares of Series A Convertible Preferred Stock were issued to Century Oil and Gas Holdings, LLC and North Peak in exchange for their interests in the Acquired Companies.

Second, 6,363,637 shares of Series A Convertible Preferred Stock were sold to the PIPE Investors at $5.50 per share ($ 11.00 per share on a post-reverse stock split basis) , raising $35.0 million in net proceeds, which were used to pay for certain liabilities and transaction expenses in the Mergers (noted above).

All shares of Series A Convertible Preferred Stock were convertible into common stock at a 0.5-to-1 ratio.

A total of 17,013,637 shares of Series A Convertible Preferred Stock were issued and outstanding as of December 31, 2025.

On February 27, 2026, all shares of Series A Convertible Preferred Stock automatically converted into 8,506,818 shares common stock of the Company.

Shareholder Agreement

At the closing of the Mergers, the Company entered into a Shareholder Agreement with Century and North Peak (together, the “ Juniper Shareholder ”), and, for certain limited provisions, Dr.

Kukes, the then Executive Chairman of the Company and The SGK 2018 Revocable Trust (a trust which Dr.

Kukes serves as trustee and beneficiary of).

The agreement granted the Juniper Shareholder board nomination rights from the closing of the Mergers until the Automatic Conversion Date, including the ability to designate one board nominee and one non-voting observer.

The agreement also provides that, following the Automatic Conversion Date, the Board will consist of six directors, with Juniper’s nominees determined by its ownership percentage of shares of the Company’s common stock on the Automatic Conversion Date.

Specifically, the right of the Juniper Shareholder to nominate Juniper Directors pursuant to the Shareholder Agreement will depend on its, together with its affiliates’, ownership of 3,181,818 shares of Company common stock issued to the Juniper Shareholder and its affiliates on February 27, 2026, on the applicable date of determination, as measured relative to a total of 13,300,815 shares of common stock issued and outstanding on February 27, 2026 (“ Juniper Beneficial Ownership ”), as follows:

if Juniper Beneficial Ownership is 50% or more, the Juniper Shareholder may nominate three Juniper Directors, including one which must be an independent director;

if Juniper Beneficial Ownership is between 30% and 49.9%, the Juniper Shareholder may nominate two Juniper Directors;

if Juniper Beneficial Ownership is between 10% and 29.9%, the Juniper Shareholder may nominate one Juniper Director;

and if Juniper Beneficial Ownership is less than 10%, the Juniper Shareholder loses the right to nominate any Juniper Directors.

The Juniper Shareholder also retains the right to remove or replace its directors, subject to Board approval and suitability requirements under SEC and NYSE standards.

At least one Juniper Shareholder director will serve on each Board committee (except the audit committee), and will chair the Compensation and Governance Committees, subject to limited exceptions.

The Shareholder Agreement also grants the shareholders registration rights, requiring the Company to use commercially reasonable efforts to file a registration statement covering the resale of the shares of common stock issuable upon conversion of the Series A Preferred Stock within 45 days of the Automatic Conversion Date, using Form S-3 or Form S-1 if necessary.

Shareholders may request underwritten offerings of at least $10 million, subject to customary agreements and underwriter approval, with limits on frequency and “grace periods” for delays.

Piggyback registration rights allow participation in offerings by the Company or other holders, subject to underwriter and priority rules.

The Company will pay related expenses and indemnify shareholders against certain Securities Act of 1933, as amended liabilities.

The Shareholder Agreement became effective at the Closing and will terminate according to its terms.

The “Shareholder Agreement” is discussed in greater detail below under “Item 10.

Directors, Executive Officers and Corporate Governance—Shareholder Agreement”.

On February 27, 2026 (the Automatic Conversion Date), the Board, with the recommendation of the Nominating and Corporate Governance Committee of the Board, and at the request of the Juniper Shareholder, pursuant to the terms of the Shareholder Agreement (discussed above), increased the number of members of the Board from five (5) to six (6), and appointed Mr.

Edward Geiser as a member of the Board and as Chairperson of the Nominating and Corporate Governance Committee of the Board of Directors, to serve until his successor has been duly elected and qualified, or until his earlier death, resignation or removal.

Also effective on February 27, 2026, director Josh Schmidt was appointed as Chairman of the Board of the Company.

Reverse Stock Split

Effective March 13, 2026, the Company effected the 1-for-20 Reverse Stock Split discussed above under “Reverse Stock Split” and as a result of the Reverse Stock Split, every twenty (20) shares of issued and outstanding common stock were automatically combined into one (1) share of common stock.

No fractional shares were issued in connection with the Reverse Stock Split.

Instead, each holder of common stock received a cash payment in lieu thereof at a price equal to the fraction of one share to which the stockholder would otherwise be entitled multiplied by the closing price per share of common stock on the NYSE American on the trading day immediately prior to the effective time of the Reverse Stock Split.

All share amounts, per-share data, earnings (loss) per share, and weighted-average shares outstanding presented in the accompanying consolidated financial statements and related notes have been retroactively adjusted to reflect the Reverse Stock Split for all periods presented.

Regulation of the Oil and Gas Industry

All of our oil and gas operations are substantially affected by federal, state and local laws and regulations.

Failure to comply with applicable laws and regulations can result in substantial penalties.

The regulatory burden on the industry increases the cost of doing business and affects profitability.

Historically, our compliance costs have not had a material adverse effect on our results of operations;

however, we are unable to predict the future costs or impact of compliance.

Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission (the “ FERC ”) and the courts, and, in Colorado, the county level.

We cannot predict when or whether any such proposals may become effective, and it is difficult to estimate the potential impact on our business from rules and regulations adopted by the federal government and states in which we operate.

We do not believe that we would be affected by any such action materially differently than similarly situated competitors.

At the state level, our operations in Colorado are regulated by the Energy & Carbon Management Commission (“ ECMC ”) (formerly the Colorado Oil & Gas Conservation Commission (“ COGCC ”)), our planned operations in Wyoming will be regulated by the Wyoming Oil and Gas Conservation Commission (“ WOGCC ”), and our New Mexico operations are regulated by the Conservation Division of the New Mexico Energy, Minerals, and Natural Resources Department (regulates oil and gas operations), New Mexico Environment Department (administers environmental protection laws), and the New Mexico State Land Office (oversees surface and mineral acres and development).

Crude oil and natural gas production operations are subject to various types of regulation, including regulation by federal and state agencies.

Federal legislation affecting the oil and gas industry is under constant review for amendment or expansion.

In addition, numerous departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations applicable to the oil and gas industry.

Such rules and regulations, among other things, require permits for the drilling of wells, regulate the spacing of wells, prevent the waste of natural gas through restrictions on flaring, require surety bonds for various exploration and production operations and regulate the calculation and disbursement of royalty payments (for federal and state leases), production taxes and ad valorem taxes.

A portion of our oil and gas leases are granted by the federal government and administered by the BLM.

Operations conducted by the Company on federal oil and gas leases must comply with numerous additional statutory and regulatory restrictions and, in the case of leases relating to tribal lands, certain tribal environmental and permitting requirements and employment rights regulations.

In addition, the U.S.

Department of the Interior (through its agencies, including the BLM and the Office of Natural Resources Revenue) has certain authority over our calculation and payment of royalties, bonuses, fines, penalties, assessments and other revenues related to our federal and tribal oil and gas leases.

In addition, the Inflation Reduction Act of 2022 (the “ IRA ”) requires that all leases granted and administered by the BLM and entered into on or after August 16, 2022, include a royalty rate of 16.67% in respect of the associated oil and gas production.

In addition, in 2022, two environmental advocacy groups filed suit against the U.S.

Department of Interior and the BLM challenging certain lease sales by the BLM beginning in December of 2017.

On January 17, 2025, a three-judge panel of the Ninth Circuit Court of Appeals upheld vacatur of various leases sold by the BLM, on grounds that the BLM violated the National Environmental Policy Act (“ NEPA ”) and the Federal Land Planning and Management Act when selling certain leases.

It remains unclear whether parties involved in the BLM Litigation will seek en banc review of the decision.

While the Company is not named in the BLM Litigation (as defendants, intervenors or otherwise), certain of the leases owned by the Company in the PRB have been “ placed in suspense ” pending a ruling by the Ninth Circuit Court of Appeals in the BLM Litigation.

It is possible that the Ninth Circuit Court of Appeals ruling could result in the cancellation of these leases.

Operations conducted by the Company are also subject to the NEPA which requires federal agencies, including the BLM, to evaluate major agency actions having the potential to significantly impact the environment.

In the course of such evaluations, an agency will prepare an environmental assessment that pertains to the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment.

Certain of the Company’s exploration, development and production activities include leasing of federal mineral interests, which will require the acquisition of governmental permits or authorizations that are subject to the procedural requirements of NEPA.

This process has the potential to delay or limit, or increase the cost of, the development of oil and natural gas projects.

Authorizations under NEPA are also subject to protest, appeal or litigation, any or all of which may delay or halt projects.

Moreover, depending on the mitigation strategies recommended in environmental assessments or Environmental Impact Statements, we could incur added costs, which may be substantial.

For example, as part of the BLM Litigation, on September 13, 2024, the U.S.

District Court for the District of Columbia issued a ruling temporarily enjoining further applications for permits to drill (“ APDs ”) with respect to the certain of the Company’s BLM leases, citing erroneous data that overstated the amount of available groundwater in the Project’s Environmental Impact Statement.

This ruling had the effect of halting federal APD approvals within the Project area until the court “ determines the appropriate final remedy ” to correct the deficiency being alleged in the case.

It is possible that the BLM’s review and ultimate approval of our APDs could be impacted by this federal court ruling and could result in the cancellation of these leases.

However, in January 2025, President Trump issued an executive order requiring the Council on Environmental Quality (“ CEQ ”) to provide guidance on implementing NEPA and to propose rescinding and replacing CEQ’s NEPA regulations with implementing regulations at the agency level.

The executive order also instructs federal agencies to adhere to only the relevant legislated requirements for environmental reviews and to prioritize efficiency and certainty over any other objectives in such reviews.

The potential impact of further changes to the NEPA regulations and statutory text therefore remains uncertain and could have an effect on our operations and our ability to obtain governmental permits.

BLM leases contain relatively standardized terms requiring compliance with detailed regulations.

Under certain circumstances, the BLM may require operations on federal leases to be suspended or terminated.

Any such suspension or termination could materially and adversely affect our interests on federal lands.

From time to time, the U.S.

Department of the Interior has also considered limiting or pausing new oil and natural gas leases on federal lands.

Any limitation or ban on permitting for oil and gas exploration and production activities on federal lands could have a material and adverse effect on our operations, financial condition and results of operations.

The transportation and sale for resale of natural gas in interstate commerce are regulated pursuant to the Natural Gas Act of 1938, as amended (the “ NGA ”), and the Natural Gas Policy Act of 1978.

These statutes are administered by the Federal Energy Regulatory Commission (“ FERC ”).

Effective January 1993, the Natural Gas Wellhead Decontrol Act of 1989 deregulated natural gas prices for all “ first sales ” of natural gas, which includes all sales by the Company of its own production.

All other sales of natural gas, such as those of natural gas purchased from third parties, remain jurisdictional sales subject to a blanket sales certificate under the NGA, which has flexible terms and conditions.

Consequently, all of our sales of natural gas may currently be made at unregulated market prices, subject to applicable contract provisions.

Jurisdictional sales, however, may be subject in the future to greater federal oversight, including the possibility that the FERC might prospectively impose more restrictive conditions on such sales.

Conversely, sales of crude oil and NGLs by the Company are made at unregulated market prices.

Proposals and proceedings that might affect the oil and gas industry are considered from time to time by Congress, the state legislatures, the FERC and other federal, state and local regulatory commissions, agencies, councils and courts.

We cannot predict when or whether any such proposals or proceedings may become effective.

It should also be noted that the oil and gas industry historically has been very heavily regulated;

therefore, there is no assurance that the approach currently being followed by such legislative bodies and regulatory commissions, agencies, councils and courts will remain unchanged.

At the state level, our operations in Colorado are regulated by the ECMC (formerly the Colorado Oil & Gas Conservation Commission (“ COGCC ”)), our operations in Wyoming are regulated by the Wyoming Oil and Gas Conservation Commission (“ WOGCC ”), and our New Mexico operations are regulated by the Conservation Division of the New Mexico Energy, Minerals, and Natural Resources Department (regulates oil and gas operations), New Mexico Environment Department (administers environmental protection laws), and the New Mexico State Land Office (oversees surface and mineral acres and development).

The Oil Conservation Division of the New Mexico Energy, Minerals, Natural Resources Department (“ EMNRD ”), and New Mexico State Land Office require the posting of financial assurance for owners and operators on privately owned or state land within New Mexico in order to provide for abandonment restoration and remediation of wells, and for the drilling of salt water disposal wells.

Regulation Affecting Production

The production of oil and natural gas is subject to United States federal and state laws and regulations, and orders of regulatory bodies under those laws and regulations, governing a wide variety of matters.

All of the jurisdictions in which we own or operate producing oil and natural gas properties have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells.

Our operations are also subject to various conservation laws and regulations.

These include the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of oil or natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

These laws and regulations may limit the amount of oil and gas wells we can drill.

Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, NGL and gas within its jurisdiction.

States do not regulate wellhead prices or engage in other similar direct regulation, but there can be no assurance that they will not do so in the future.

The effect of such future regulations may be to limit the amounts of oil and gas that may be produced from our wells, negatively affect the economics of production from these wells or limit the number of locations we can drill.

The failure to comply with the rules and regulations of oil and natural gas production and related operations can result in substantial penalties.

State laws also may prohibit the venting or flaring of natural gas, which may impact rates of production of crude oil and natural gas from our leases.

Leases covering state or federal lands often include additional laws, regulations and conditions which can limit the location, timing and number of wells we can drill and impose other requirements on our operations, all of which can increase our costs.

Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Regulation Affecting Sales and Transportation of Commodities

Sales prices of gas, oil, condensate and NGL are not currently regulated and are made at market prices.

Although prices of these energy commodities are currently unregulated, the United States Congress historically has been active in their regulation.

We cannot predict whether new legislation to regulate oil and gas, or the prices charged for these commodities might be proposed, what proposals, if any, might actually be enacted by the United States Congress or the various state legislatures and what effect, if any, the proposals might have on our operations.

Sales of oil and natural gas may be subject to certain state and federal reporting requirements.

The price and terms of service of transportation of the commodities, including access to pipeline transportation capacity, are subject to extensive federal and state regulation.

Such regulation may affect the marketing of oil and natural gas produced by the Company, as well as the revenues received for sales of such production.

Gathering systems may be subject to state ratable take and common purchaser statutes.

Ratable take statutes generally require gatherers to take, without undue discrimination, oil and natural gas production that may be tendered to the gatherer for handling.

Similarly, common purchaser statutes generally require gatherers to purchase, or accept for gathering, without undue discrimination as to source of supply or producer.

These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply.

These statutes may affect whether and to what extent gathering capacity is available for oil and natural gas production, if any, of the drilling program and the cost of such capacity.

Further state laws and regulations govern rates and terms of access to intrastate pipeline systems, which may similarly affect market access and cost.

The FERC regulates interstate natural gas pipeline transportation rates and service conditions.

The FERC is continually proposing and implementing new rules and regulations affecting interstate transportation.

The stated purpose of many of these regulatory changes is to ensure terms and conditions of interstate transportation service are not unduly discriminatory or unduly preferential, to promote competition among the various sectors of the natural gas industry and to promote market transparency.

We do not believe that our drilling program will be affected by any such FERC action in a manner materially differently than other similarly situated natural gas producers.

In addition to the regulation of natural gas pipeline transportation, the FERC has additional jurisdiction over the purchase or sale of gas or the purchase or sale of transportation services subject to the FERC’s jurisdiction pursuant to the Energy Policy Act of 2005 (“ EPAct 2005 ”).

Under the EPAct 2005, it is unlawful for “ any entity, ” including producers such as us, that are otherwise not subject to FERC’s jurisdiction under the Natural Gas Act of 1938 (“ NGA ”) to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of gas or the purchase or sale of transportation services subject to regulation by FERC, in contravention of rules prescribed by the FERC.

The FERC’s rules implementing this provision make it unlawful, in connection with the purchase or sale of gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud;

to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading;

or to engage in any act or practice that operates as a fraud or deceit upon any person.

EPAct 2005 also gives the FERC authority to impose civil penalties for violations of the NGA and the Natural Gas Policy Act of 1978 up to $1.5 million per day, per violation.

The anti-manipulation rule applies to activities of otherwise non-jurisdictional entities to the extent the activities are conducted “ in connection with ” gas sales, purchases or transportation subject to FERC jurisdiction, which includes the annual reporting requirements under FERC Order No.

704 (defined below).

In December 2007, the FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (“ Order No.

Under Order No.

704, any market participant, including a producer that engages in certain wholesale sales or purchases of gas that equal or exceed 2.2 trillion BTUs of physical natural gas in the previous calendar year, must annually report such sales and purchases to the FERC on Form No.

552 on May 1 of each year.

552 contains aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to the formation of price indices.

Not all types of natural gas sales are required to be reported on Form No.

It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order No.

704 is intended to increase the transparency of the wholesale gas markets and to assist the FERC in monitoring those markets and in detecting market manipulation.

We are not currently subject to the requirement to report on Form No.

552, as our sales of oil and natural gas do not rise to the minimum level required for reporting by Order No.

The FERC also regulates rates and terms and conditions of service on interstate transportation of liquids, including oil and NGL, under the Interstate Commerce Act, as it existed on October 1, 1977 (“ ICA ”).

Prices received from the sale of liquids may be affected by the cost of transporting those products to market.

The ICA requires that certain interstate liquids pipelines maintain a tariff on file with the FERC.

The tariff sets forth the established rates as well as the rules and regulations governing the service.

The ICA requires, among other things, that rates and terms and conditions of service on interstate common carrier pipelines be “ just and reasonable.

” Increases in liquids transportation rates may result in lower revenue and cash flows for the Company.

Such pipelines must also provide jurisdictional service in a manner that is not unduly discriminatory or unduly preferential.

Shippers have the power to challenge new and existing rates and terms and conditions of service before the FERC.

In addition, due to common carrier regulatory obligations of liquids pipelines, capacity must be prorated among shippers in an equitable manner in the event there are nominations in excess of capacity or new shippers.

Therefore, new shippers or increased volume by existing shippers may reduce the capacity available to us.

Any prolonged interruption in the operation or curtailment of available capacity of the pipelines that we rely upon for liquids transportation could have a material adverse effect on our business, financial condition, results of operations and cash flows.

However, we believe that access to liquids pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.

Rates for intrastate pipeline transportation of liquids are subject to regulation by state regulatory commissions.

The basis for intrastate liquids pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate liquids pipeline rates, varies from state to state.

We believe that the regulation of liquids pipeline transportation rates will not affect our operations in any way that is materially different from the effects on our similarly situated competitors.

In addition to the FERC’s regulations, we are required to observe anti-market manipulation laws with regard to our physical sales of energy commodities.

In November 2009, the Federal Trade Commission (“ FTC ”) issued regulations pursuant to the Energy Independence and Security Act of 2007, intended to prohibit market manipulation in the petroleum industry.

Violators of the regulations face civil penalties of up to $1.3 million per violation per day.

In July 2010, Congress passed the Dodd-Frank Act, which incorporated an expansion of the authority of the Commodity Futures Trading Commission (“ CFTC ”) to prohibit market manipulation in the markets regulated by the CFTC.

This authority, with respect to oil swaps and futures contracts, is similar to the anti-manipulation authority granted to the FTC with respect to oil purchases and sales.

In July 2011, the CFTC issued final rules to implement their new anti-manipulation authority.

The rules subject violators to a civil penalty of up to the greater of $1.1 million or triple the monetary gain to the person for each violation.

Environmental and Occupational Safety and Health Matters

Our operations are subject to stringent federal, state and local laws and regulations governing occupational safety and health aspects of our operations, the discharge of materials into the environment and environmental protection.

Numerous governmental entities, including the U.S.

Environmental Protection Agency (“ EPA ”) and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions.

These laws and regulations may, among other things (i) require the acquisition of permits to conduct drilling and other regulated activities;

(ii) restrict the types, quantities and concentration of various substances that can be released into the environment or injected into formations in connection with oil and natural gas drilling and production activities;

(iii) limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas;

(iv) require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells;

(v) apply specific health and safety criteria addressing worker protection;

and (vi) impose substantial liabilities for pollution resulting from drilling and production operations.

Any failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of corrective or remedial obligations, the occurrence of delays or restrictions in permitting or performance of projects, and the issuance of orders enjoining performance of some or all of our operations.

These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible.

The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability.

The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly well drilling, construction, completion or water management activities, or waste handling, storage transport, disposal, or remediation requirements could have a material adverse effect on our financial position and results of operations.

We may be unable to pass on such increased compliance costs to our customers.

Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons.

Continued compliance with existing requirements is not expected to materially affect us.

However, there is no assurance that we will be able to remain in compliance in the future with such existing or any new laws and regulations or that such future compliance will not have a material adverse effect on our business and operating results.

The following is a summary of the more significant existing and proposed environmental and occupational safety and health laws, as amended from time to time, to which our business operations are or may be subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

Air Emissions

Our operations are subject to the Clean Air Act (the “ CAA ”) and comparable state and local requirements.

The CAA contains provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations.

The EPA and state governments continue to develop regulations to implement these requirements.

We may be required to make certain capital investments in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues.

Federal Air Regulation

The EPA adopted regulations requiring the reporting of GHG emissions from specific categories of higher GHG emitting sources in the U.S., including certain crude oil and natural gas production facilities, which include certain of our operations.

Information in such reporting may form the basis for further GHG regulation.

Further, the EPA has continued with its comprehensive strategy for further reducing methane emissions from oil and gas operations, with a final rule being issued in June 2016 as part of the Subpart OOOOa NSPS.

In November 2021, the EPA issued a proposed rule intended to reduce methane emissions from oil and gas sources.

The proposed rule sought to make the existing regulations in Subpart OOOOa more stringent and create a Subpart OOOOb to expand reduction requirements for new, modified, and reconstructed oil and gas sources, including standards focusing on certain source types that have never been regulated under the CAA (including intermittent vent pneumatic controllers, associated gas, and liquids unloading facilities).

In addition, the proposed rule sought to establish “Emissions Guidelines,” creating a Subpart OOOOc that would require states to develop plans to reduce methane emissions from existing sources that must be at least as effective as presumptive standards set by the EPA.

In November 2022, the EPA issued a proposed rule supplementing the November 2021 proposed rule.

Among other things, the November 2022 supplemental proposed rule removed an emissions monitoring exemption for small wellhead-only sites and created a new third-party monitoring program to flag large emissions events, referred to in the proposed rule as “super emitters.” The EPA announced a final rule in December 2023, which, among other things, requires the phase out of routine flaring of natural gas from new crude oil wells and routine leak monitoring at all well sites and compressor stations.

Notably, EPA updated the applicability date for Subparts OOOOb and OOOOc to December 6, 2022, meaning that sources constructed prior to that date will be considered existing sources with later compliance dates under state plans.

The final rule gives states, along with federal tribes that wish to regulate existing sources, two years to develop and submit their plans for reducing methane from existing sources until March 2026.

The final emissions guidelines under Subpart OOOOc provide until 2029 for existing sources to comply.

The final rule is subject to ongoing litigation but remains in effect.

More recently, the EPA finalized on March 8, 2024, additional final NSPS OOOO program final rules—referred to as Subparts OOOOb and OOOOc—which, became effective May 7, 2024, and are expected to have a significant impact on the upstream and midstream oil and gas sectors from an operational cost perspective.

The rules impose additional methane and VOC emissions limitations from new, modified, and reconstructed sources, and will regulate existing sources for the first time under the NSPS OOOOc program by requiring states to implement plans that meet or exceed federally established emission reduction guidelines for existing oil and natural gas facilities.

Although the bulk of the 2012 and 2016 standards are currently in effect, future implementation and the ultimate scope of VOC and methane emissions for the oil and gas production, transmission, and storage industry segments are uncertain at this time and could be modified further as a result of ongoing rulemakings and expected legal challenges.

The EPA’s GHG rules could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities.

Environmental Regulation Generally

We are subject to various federal, state and local laws and regulations covering the discharge or release of materials into the environment or otherwise relating to the protection of the environment.

These laws and regulations affect our operations and costs as a result of their effect on crude oil and natural gas exploration, development and production operations and related activities (e.g., carbon capture and storage).

Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, including the assessment of monetary penalties, criminal prosecution, the imposition of investigatory and remedial obligations, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and the issuance of orders enjoining future operations or imposing additional compliance requirements.

In addition, we have acquired certain oil and gas properties from third parties whose actions with respect to the management and disposal or release of hydrocarbons or other wastes were not under our control.

Under environmental laws and regulations, we could be required to remove or remediate wastes disposed of or released by prior owners or operators.

We also could incur costs related to the clean-up of third-party sites to which we sent regulated substances for disposal or to which we sent equipment for cleaning, and for damages to natural resources or other claims related to releases of regulated substances at such third-party sites.

In addition, we could be responsible under environmental laws and regulations for oil and gas properties in which we previously owned or currently own an interest but were or are not currently the operator.

Moreover, we are currently subject to certain reporting requirements promulgated by U.S.

Environmental Protection Agency’s (the “ EPA ”) regarding, among other things, GHG emissions and other fugitive emissions.

And, as discussed further below, we are also subject to federal, state and local laws and regulations regarding hydraulic fracturing and other aspects of our operations.

Compliance with environmental laws and regulations increases our overall cost of business, but has not had, to date, a material adverse effect on our operations, financial condition, results of operations or capital expenditures (for environmental control facilities or otherwise).

In addition, it is not anticipated, based on current laws and regulations, that we will be required in the near future to expend amounts (whether for environmental control facilities or otherwise) that are material in relation to our total exploration and development expenditure program in order to comply with such laws and regulations.

However, we are unable to predict (i) the timing, scope and effect of any currently proposed or future laws or regulations regarding the environment and (ii) the ultimate cost of compliance or the ultimate effect on our operations, financial condition, results of operations and capital expenditures relating to such future laws and regulations.

The direct and indirect cost of such laws and regulations (if enacted) could materially and adversely affect our operations, financial condition, results of operations and capital expenditures.

However, in January 2025, President Trump issued an executive order directing the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions that are unduly burdensome on the identification, development, or use of domestic energy resources.

Consequently, future implementation and enforcement of the final rule remains uncertain at this time.

Changes in the U.S.

presidential administration following the 2024 presidential election could also affect the implementation of the NSPS Subpart OOOOb and OOOOc rules.

In October 2015, the EPA finalized its rule lowering the earlier 75 part per billion (“ ppb ”) national ambient air quality standards (“ 2008 NAAQS ”) for ozone under the CAA to 70 ppb (“ 2015 NAAQS ”).

The state of Colorado’s Denver Metro and North Front Range (“ DM/NFR ”) air quality control region has been unable to attain the 2008 and 2015 ozone NAAQS since their adoption, and its existing non-attainment status for the 2008 NAAQS was reclassified from “serious” to “severe” in 2022 due to violations at area monitors during the 2020 ozone season.

A “severe” classification triggers significant additional obligations under the CAA and state laws and will result in new and more stringent air quality control requirements applicable to our operations in Colorado and significant operating costs and delays in obtaining necessary permits for new and modified production facilities.

Among other requirements, a “severe” classification for the 2008 NAAQS may require additional permitting in the nonattainment area for any source with the potential to emit more than 25 tons per year of volatile organic compounds or nitrogen oxides.

Additionally, the DM/NFR’s non-attainment boundary for the 2015 NAAQS was successfully challenged by environmental groups and local governments seeking to expand the boundary to include all of northern Weld County in the case of Clean Wisconsin v.

18-1203, in which the D.C.

Circuit Court remanded the boundary determination to the EPA for further support or re-designation.

In response, the EPA chose to re-designate the boundary for the 2015 ozone NAAQS to include all of Weld County, which action became effective on December 30, 2021.

Weld County challenged the EPA’s action upon remand in the D.C.

Circuit, and the D.C.

Circuit Court denied Weld County’s petition for review in June 2023.

of County Comm.

of Weld County v.

While the Permian Basin in New Mexico has not been designated as being in nonattainment with federal ozone standards, the EPA’s 2023 proposal to designate the Permian Basin as being in nonattainment remains pending.

In November 2022, the Bureau of Land Management (“ BLM ”) published a proposed rule that would regulate venting, flaring and leaks during oil and gas production activities on federal and Indian leases.

If finalized as proposed, the rule would limit gas that may be flared royalty-free during well completions, production testing, and emergencies;

establish a monthly volume limit on royalty-free flaring due to pipeline capacity constraints, midstream processing failures, or other similar events;

require vapor recovery systems on oil tanks;

require operators to maintain leak detection and repair (“ LDAR ”) programs;

prohibit the use of certain natural-gas-activated pneumatic controllers and pneumatic diaphragm pumps;

and require operators to submit waste minimization plans with applications for permit to drill, among other requirements.

State Air Regulation

Accordingly, future implementation and enforcement of certain environmental laws or regulations are uncertain at this time.

Climate Change Regulations

Local, state, federal and international regulatory bodies have been increasingly focused on GHG emissions and climate change issues in recent years.

Congress has, from time to time, proposed legislation for imposing restrictions on, or requiring fees or carbon taxes in respect of, GHG emissions.

Further, the IRA imposes a methane emissions charge on certain oil and gas facilities, including petroleum and natural gas production facilities that exceed certain emissions thresholds.

The charge will be levied annually based on emissions reported under the EPA’s GHG reporting program.

In November 2024, the EPA finalized a regulation to implement the IRA’s Waste Emissions Charge, which became effective on January 1, 2025.

The fee imposed under the Methane Emissions Reduction Program for 2024 is $900 per ton emitted over annual methane emissions thresholds, and increases to $1,200 in 2025, and $1,500 in 2026.

In January 2025, industry associations challenged the Waste Emissions Charge rule in the D.C.

Circuit Court of Appeals.

Also in January 2025, President Trump issued an executive order directing the heads of all federal agencies to identify and begin the processes to suspend, revise or rescind all agency actions that are unduly burdensome on the identification, development or use of domestic energy resources.

In late February 2025, the newly seated Congress successfully passed a joint resolution (H.J.

35) using the Congressional Review Act (CRA) to officially disapprove of the EPA’s November 2024 rule implementing the methane fee and President Trump signed this resolution into law in March 2025, effectively nullifying the previously adopted Methane Emissions Reduction Program.

In addition, based on the timing of the rule's finalization and statements from congressional Republicans, the waste emissions charge rule is potentially vulnerable to repeal by Congress under the Congressional Review Act, and the IRA may also be subject to amendment or repeal through Congressional budget reconciliation.

Consequently, future implementation and enforcement of these rules remains uncertain at this time.

The EPA has adopted regulations for certain large sources regulating GHG emissions as pollutants under the federal Clean Air Act.

Further, the EPA, in May 2016, issued regulations that require operators to reduce methane emissions and emissions of volatile organic compounds (“ VOC ”) from new, modified and reconstructed crude oil and natural gas wells and equipment located at natural gas production gathering and booster stations, gas processing plants and natural gas transmission compressor stations.

In November 2021, the EPA proposed a rule to further reduce methane and VOC emissions from new and existing sources in the oil and natural gas sector, and, in November 2022, the EPA issued a supplemental proposal to expand its November 2021 proposed rule, including proposed regulation of additional sources of methane and VOC emissions, such as abandoned and unplugged wells.

The EPA issued the final new source performance standards and emissions guidelines for new and existing oil and gas facilities in December 2023, and although in effect, the final rule is subject to ongoing litigation.

Furthermore, in January 2025, President Trump issued an executive order directing the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions that are unduly burdensome on the identification, development, or use of domestic energy resources.

In 2019, Colorado enacted Senate Bill 19-181 (“ SB 19-181 ”), which requires, among other things, that the Air Quality Control Commission (“ AQCC ”) adopt additional rules to minimize emissions of methane and other hydrocarbons and nitrogen oxides from the entire oil and gas fuel cycle.

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In effect, the petition for rulemaking calls for a blanket prohibition on oil and gas development in much of Colorado.

The COGCC denied the petition;

however, the COGCC initiated a cumulative impacts stakeholder process to determine how best to address cumulative impacts going forward, which may include additional regulations.

The COGCC (now ECMC) denied the petition;

however, the COGCC (now the ECMC) initiated a cumulative impacts stakeholder process to determine how best to address cumulative impacts going forward, which may include additional regulations.

Since 2022, the ECMC has introduced regulatory measures impacting the oil and gas industry, including:

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In addition, the NMOCD adopted a rule in August 2022 that requires oil and natural gas producers in counties that are at risk of non-attainment of federal ozone standards to, among other things, check emission rates and have those calculations certified by a qualified engineer, perform enhanced checks for leaks, repair those leaks within 15 days of discovery, and maintain records to demonstrate continuous compliance.

Compliance with these and other air pollution control, air monitoring, gas capture, and permitting requirements has the potential to delay the development of crude oil and natural gas projects and increase our costs of development and production, which costs could be significant.

Hydraulic Fracturing

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations.

We regularly use hydraulic fracturing as part of our operations.

Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemicals under pressure into targeted geological formations to fracture the surrounding rock and stimulate production.

Hydraulic fracturing is typically regulated by state oil and natural gas commissions.

However, several federal agencies have asserted regulatory authority over certain aspects of the process.

The federal Safe Drinking Water Act (“ SDWA ”) and comparable state statutes may restrict the disposal, treatment, or release of water produced or used during oil and gas development.

Subsurface emplacement of fluids, primarily via disposal wells or enhanced oil recovery wells (“ EOR Wells ”), is governed by federal or state regulatory authorities that, in some cases, include the state oil and gas regulatory or the state’s environmental authority.

The federal Energy Policy Act of 2005 amended the Underground Injection Control provisions of the SDWA to expressly exclude certain hydraulic fracturing from the definition of “underground injection,” but disposal of hydraulic fracturing fluids and produced water or their injection for EOR Wells is not excluded.

Federal agencies have periodically considered additional regulation of hydraulic fracturing.

The EPA has published guidance for issuing underground injection permits that would regulate hydraulic fracturing using diesel fuel.

This guidance eventually could encourage other regulatory authorities to adopt permitting and other restrictions on the use of hydraulic fracturing.

In June 2016, the EPA finalized regulations that address discharges of wastewater pollutants from onshore unconventional extraction facilities to publicly-owned treatment works.

The EPA also published a study of the impact of hydraulic fracturing on drinking water resources, which concluded that drinking water resources can be affected by hydraulic fracturing under specific circumstances.

The results of this study could result in additional regulations, which could lead to operational burdens similar to those described above;

however, the EPA has taken no further action in response to the study to date.

In April 2024, the BLM finalized a rule to reduce the waste of natural gas from venting, flaring and leaks during oil and gas production activities on federal and Indian leases, which became effective in June 2024.

However, numerous states challenged the rule, and litigation is ongoing in the District of North Dakota, which granted a preliminary injunction enjoining BLM from enforcing the rule in the plaintiff states in September 2024.

As a result, future implementation and enforcement of this rule remains uncertain at this time.

In addition, oil and natural gas exploration, development and production activities on federal lands, including American Indian lands and lands administered by the BLM, are subject to the National Environmental Policy Act (“ NEPA ”).

The NEPA requires federal agencies, including the BLM, to evaluate major agency actions having the potential to significantly impact the environment.

In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment.

Authorizations under the NEPA also are subject to protest, appeal, or litigation, which can delay or halt projects.

In July 2020, the Council on Environmental Quality (“ CEQ ”) revised the NEPA’s implementing regulations to make the NEPA process more efficient, effective, and timely.

The rule required federal agencies to develop procedures consistent with the new rule within one year of the rule’s effective date (which was extended to two years in June 2021).

These regulations are subject to ongoing litigation in several federal district courts, and in October 2021, CEQ issued a notice of proposed rulemaking to amend the NEPA regulatory changes adopted in 2020 in two phases.

Phase I of the CEQ’s proposed rulemaking process was finalized in April 2022, and generally restored provisions that were in effect prior to 2020.

In July 2023, CEQ issued a proposed rule for the Phase II rulemaking.

The proposed Phase II rule restores certain mitigation language from the pre-2020 version of the NEPA regulations, proposes further revisions to ensure the NEPA process “provides for efficient and effective environmental reviews,” and meets environmental, environmental justice, and climate change objectives.

The final rule was made effective May 1, 2024.

However, at least twenty states challenged the Phase II rule in federal district court.

In addition, in January 2025, President Trump issued executive orders directing (i) CEQ to provide guidance on implementing NEPA and to propose rescinding and replacing CEQ’s NEPA regulations with implementing regulations at the agency level and (ii) federal agencies to adhere to only the relevant legislated requirements for environmental reviews and to prioritize efficiency and certainty over any other objectives in such reviews.

In February 2025, CEQ sent an interim final rule to the White House Office of Management and Budget that would immediately withdraw the NEPA implementing regulations.

The potential impact of further changes to the NEPA regulations and statutory text therefore remains uncertain and could have an effect on our business and operations.

On January 20, 2021, the Acting U.S.

Interior Secretary, instituted a moratorium on new oil and gas leases and permits on federal onshore and offshore lands, which a federal court blocked with a preliminary injunction in June 2021, which injunction is being appealed.

President Biden resumed onshore oil and gas lease sales on federal lands effective April 18, 2022.

A total of approximately 17% of the Company’s acreage in New Mexico, 1% of the Company’s acreage in Colorado, and 4% of the Company’s acreage in Wyoming is located on federal lands.

It is currently unclear whether future moratoriums will be imposed, if any, and whether such actions herald the start of a change in federal policies regarding the grant of oil and gas permits on federal lands.

Apart from these ongoing federal and state initiatives, some state and local governments where we operate have adopted their own new requirements on hydraulic fracturing and other oil and gas operations and, in some cases, have proposed initiatives restricting or banning oil and gas development altogether.

For example, Colorado Senate Bill 19-181 amended state law to give municipalities and counties greater local control over siting and permitting of oil and gas locations, and some municipalities within the state have implemented regulations within their jurisdictions.

Any successful bans or moratoria where we operate, whether at the state or local level, could increase the costs of our operations, impact our profitability, and even prevent us from drilling in certain locations which could adversely impact our ability to develop our reserves.

In addition, in light of concerns about seismic activity potentially being triggered by the injection of produced waters into underground wells, regulators in the states in which we operate have adopted additional requirements related to seismic safety for hydraulic fracturing activities or the underground injection of fluid wastes.

For example, the regulations that the ECMC adopted in November 2020 impose various requirements on the underground injection of fluid wastes to further seismic safety and protect the environment.

In New Mexico, the New Mexico Oil Conservation Division (“ OCD ”) implemented a Seismicity Response Protocol that is implemented either through voluntary actions by operators and/or orders issued by the OCD in response to increased seismic activity believed to be related to injection wells throughout New Mexico.

Any regulation that restricts our ability to dispose of produced waters or increases the cost of doing business could have a material adverse effect on our business.

At this time, it is not possible to estimate the potential impact on our business of recent state and local actions or the enactment of additional federal or state legislation or regulations affecting hydraulic fracturing.

The adoption of future federal, state, or local laws or implementing regulations imposing new environmental obligations on, or otherwise limiting, our operations could make it more difficult and more expensive to complete crude oil and natural gas wells, increase our costs of compliance and doing business, delay or prevent the development of certain resources (including especially shale formations that are not commercial without the use of hydraulic fracturing), or alter the demand for and consumption of our products.

The outcome of such legislation or regulation may have a material and adverse impact on our cash flows and results of operations.

At the international level, the U.S., in December 2015, participated in the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France.

The Paris Agreement, which was adopted at the conference and went into effect in November 2016, calls for nations to undertake efforts with respect to global temperatures and set GHG emissions reduction goals every 5 years beginning in 2020.

In February 2021, the Biden Administration announced reentry of the U.S.

into the Paris Agreement along with a new “ nationally determined contribution ” for U.S.

GHG emissions that would achieve emissions reductions of at least 50% relative to 2005 levels by 2030.

Pursuant to its obligations as a signatory to the Paris Agreement, the United States set a target to reduce its GHG emissions by 50-52% by the year 2030 as compared with 2005 levels.

In addition, in 2021, the Biden Administration publicly announced the Global Methane Pledge, a pact that aims to reduce global methane emissions at least 30% below 2020 levels by 2030, including “ all feasible reductions ” in the energy sector.

Since its formal launch at the United Nations Framework Convention on Climate Change 26th Conference of the Parties (“ COP26 ”), over 150 countries have joined the pledge.

COP26 concluded with the finalization of the Glasgow Climate Pact (the “ Glasgow Pact ”), which stated long-term global goals (including those in the Paris Agreement) to limit the increase in the global average temperature and emphasized reductions in GHG emissions.

At the 27th Conference of the Parties, the United States agreed, in conjunction with the European Union and a number of other partner countries, to develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity natural gas.

In December 2023 at the 28th Conference of the Parties, nearly 200 countries entered into an agreement that calls for actions towards achieving, at a global scale, a tripling of renewable energy capacity and doubling energy efficiency improvements by 2030.

The goals of the agreement, among other things, are to contribute to the transition away from fossil fuels, reduce methane emissions and increase renewable energy capacity, among other things, in order to achieve global net zero emissions by 2050.

Most recently, at the 29th Conference of the Parties (“ COP29 ”), delegates approved rules to operationalize international carbon markets under Article 6 of the Paris Agreement, including a new Paris Agreement Crediting Mechanism to trade UN-approved carbon credits.

Additionally, participants at COP29 representing 159 countries met to review progress toward the goals of the Global Methane Pledge and the addition of nearly $500 million in new grant funding for methane abatement.

On January 20th, 2025, the Trump Administration announced its intention to withdraw from the Paris Agreement and all other agreements made under the United Nations Framework Convention on Climate Change.

The full impact of these actions remains unclear at this time.

However, various state and local governments in the U.S.

have publicly committed to furthering the goals of the Paris Agreement and many of these initiatives are expected to continue.

We are unable to predict the timing, scope and effect of any currently proposed or future investigations, laws, regulations, treaties or policies regarding climate change and GHG emissions (including any laws and regulations that may be enacted in the U.S.), but the direct and indirect costs of such investigations, laws, regulations, treaties or policies (if enacted, issued or applied) could materially and adversely affect our operations, financial condition, results of operations and capital expenditures.

Regulation of Hydraulic Fracturing and Other Operations

Hydraulic fracturing technology, which has been used by the oil and gas industry for more than 60 years and continues to evolve, enables us to produce crude oil and natural gas that otherwise would not be recovered.

While hydraulic fracturing has historically been regulated by state oil and natural gas commissions, the practice has become increasingly controversial in certain parts of the country, resulting in increased scrutiny and regulation.

For example, the EPA’s wastewater pretreatment standards prohibit onshore unconventional oil and natural gas extraction facilities from sending wastewater to publicly-owned treatment works.

This restriction of disposal options for hydraulic fracturing waste and other changes to environmental requirements may result in increased costs.

In addition to the above-described federal regulations, some state and local governments have imposed, or have considered imposing, various conditions and restrictions on drilling and completion operations, including requirements regarding casing and cementing of wells, testing of nearby water wells, restrictions on access to, and usage of, water, disclosure of the chemical additives used in hydraulic fracturing operations, restrictions on the type of chemical additives that may be used in hydraulic fracturing operations and restrictions on drilling or injection activities on certain lands lying within wilderness wetlands, ecologically or seismically sensitive areas and other protected areas.

Such federal, state and local permitting and disclosure requirements, operating restrictions, conditions or prohibitions could lead to operational delays and increased operating and compliance costs and, moreover, could delay or effectively prevent the development of crude oil and natural gas from formations which would not be economically viable without the use of hydraulic fracturing.

Compliance with laws and regulations relating to hydraulic fracturing and other aspects of our operations increases our overall cost of business, but has not had, to date, a material adverse effect on our operations, financial condition, results of operations or capital expenditures.

In addition, it is not anticipated, based on current laws and regulations, that we will be required in the near future to expend amounts that are material in relation to our total exploration and development expenditure program in order to comply with such laws and regulations.

However, we are unable to predict (i) the timing, scope and effect of any currently proposed or future laws or regulations regarding hydraulic fracturing in the U.S.

or other aspects of our operations;

and (ii) the ultimate cost of compliance or the ultimate effect on our operations, financial condition, results of operations and capital expenditures relating to such future laws and regulations.

The direct and indirect costs of such laws and regulations (if enacted) could materially and adversely affect our operations, financial condition, results of operations and capital expenditures.

Other State Laws

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We routinely monitor our operations and new rules and regulations which may affect our operations, to ensure that we maintain compliance.

In New Mexico, the Company, through its New Mexico operating subsidiary RAZO, has entered into a Stipulated Final Order (“ SFO ”) with the OCD pursuant to which, among other things, RAZO agreed to reimburse the OCD for actual costs incurred by the OCD for plugging and abandoning approximately 299 inactive legacy wells in the Permian Basin Asset at a rate of $2.00 per gross barrel of oil sold by RAZO during any production reporting period, subject to a minimum payment of $30,000 per month by RAZO.

In New Mexico, the Company, through its New Mexico operating subsidiary RAZO, has entered into a Stipulated Final Order with the OCD pursuant to which, among other things, RAZO agreed to reimburse the OCD for actual costs incurred by the OCD for plugging and abandoning approximately 299 inactive legacy wells in the Permian Basin Asset at a rate of $2.00 per gross barrel of oil sold by RAZO during any production reporting period, subject to a minimum payment of $30,000 per month by RAZO.

RAZO has been timely paying each reimbursement invoice received from the OCD in accordance with the SFO and is in full compliance with the SFO.

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If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, including, for example, on federal and American Indian lands, we could incur potentially significant added cost to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.

Moreover, because most of our operations are conducted in two particular areas, the Permian Basin in New Mexico and the D-J Basin in Colorado, and potentially extending into Wyoming in the future, legal restrictions imposed in those areas will have a significantly greater adverse effect than if we had our operations spread out amongst several diverse geographic areas.

Consequently, in the event that local or state restrictions or prohibitions are adopted in the Permian Basin in New Mexico and/or the D-J Basin in Colorado and/or Wyoming that impose more stringent limitations on the production and development of oil and natural gas, we may incur significant costs to comply with such requirements or may experience delays or curtailment in the pursuit of exploration, development, or production activities, and possibly be limited or precluded in the drilling of wells or in the amounts that we are ultimately able to produce from our reserves.

Moreover, because most of our operations are conducted in three particular areas, the D-J Basin in Colorado, the PRB in Wyoming, and the Permian Basin in New Mexico, legal restrictions imposed in those areas will have a significantly greater adverse effect than if we had our operations spread out amongst several diverse geographic areas.

Consequently, in the event that local or state restrictions or prohibitions are adopted in the D-J Basin in Colorado, and/or the PRB and/or the D-J Basin in Wyoming, and/or the Permian Basin in New Mexico that impose more stringent limitations on the production and development of oil and natural gas, we may incur significant costs to comply with such requirements or may experience delays or curtailment in the pursuit of exploration, development, or production activities, and possibly be limited or precluded in the drilling of wells or in the amounts that we are ultimately able to produce from our reserves.

Any such increased costs, delays, cessations, restrictions or prohibitions could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity.

Water Discharges

The Federal Clean Water Act (“ CWA ”) and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas wastes, into or near navigable and other regulated waters.

The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state.

The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S.

Army Corps of Engineers (the “ USACE ”).

Whether CWA permitting is required depends upon whether and the extent to which “Waters of the United States” (“ WOTUS ”) may be impacted by the planned activity—for example, construction of drilling pads, access roads, or pipelines.

Rulemaking by EPA and the USACE to define WOTUS has been heavily litigated, resulting in the rule taking effect at times in some states but not others and creating definitions that are more inclusive of certain waters effective in some states and those that are less inclusive effective in other states.

The EPA’s and USACE’s WOTUS definition rulemaking published in the Federal Register on January 18, 2023 (the “ January 2023 Rule ”) incorporated “relatively permanent” and “significant nexus” standards for determining jurisdiction over adjacent wetlands and additional waters, thereby expanding the types of waters that could be considered WOTUS.

However, this WOTUS definition was litigated and eventually amended on August 29, 2023, when the EPA and USACE issued a final rule to conform the WOTUS definition to the U.S.

Supreme Court’s May 25, 2023, decision in Sackett v.

Environmental Protection Agency , which invalidated parts of the January 2023 Rule.

With the August 2023 rulemaking, the EPA and USACE implemented a narrower definition of WOTUS by, for example, removing “interstate wetlands”;

redefining “adjacent” to mean “having a continuous surface connection”;

and removing the “significant nexus” standard from the provisions regarding tributaries, adjacent wetlands, and intrastate lakes and ponds.

To the extent any litigation or future amendments to the rule expand the scope of the Clean Water Act’s jurisdiction, the Company could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas or in connection with stream crossings and preparation and implementation of oil spill prevention, control, and countermeasure (“ SPCC ”) plans.

The primary federal law related specifically to oil spill liability is the Oil Pollution Act of 1990 (“ OPA ”), which amends and augments the oil spill provisions of the CWA and imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening waters of the United States or adjoining shorelines.

In addition, operators of certain oil and natural gas facilities must develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance.

Owners or operators of a facility, vessel or pipeline that is a source of an oil discharge or that poses a substantial threat of discharge is one type of “responsible party” who is liable.

The OPA applies joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages.

Although defenses exist, they are limited.

As such, a violation of the OPA has the potential to adversely affect the Company’s operations.

SPCC regulations promulgated under the CWA and later amended by the Oil Pollution Act of 1990 require operators of certain oil and natural gas facilities that store oil in more than threshold quantities, the release of which could reasonably be expected to reach jurisdictional waters, to develop, implement, and maintain an SPCC plan.

The SPCC plan must describe oil handling operations, spill prevention practices, discharge or drainage controls, and the personnel, equipment and resources at the facility that are used to prevent oil spills from reaching navigable and other regulated waters or adjoining shorelines, and reviewed at least every five years.

Pursuant to CWA laws and regulations, the Company may also be required to obtain and maintain approvals or permits for the discharge of wastewater, including produced water, or storm water.

Obtaining permits has the potential to delay the development of oil and natural gas projects.

These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances and may impose substantial potential liability for the costs of removal, remediation and damages.

Hazardous Substances and Wastes

The Federal Resource Conservation and Recovery Act (“ RCRA ”), and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes.

Pursuant to rules issued by the EPA, the individual states administer some or all of the provisions of the RCRA, sometimes in conjunction with their own, more stringent requirements.

Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of oil or natural gas, if properly handled, are currently exempt from regulation as hazardous waste under the RCRA and, instead, are regulated under the RCRA’s less stringent non-hazardous waste provisions, state laws or other federal laws.

However, it is possible that certain oil and natural gas drilling and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future.

Stricter regulation of wastes generated during our operations could result in an increase in our, as well as the oil and natural gas exploration and production industry’s costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.

The Comprehensive Environmental Response, Compensation and Liability Act (“ CERCLA ”), also known as the Superfund law, and comparable state laws impose joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment.

These persons include the current and former owners and operators of the site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site.

Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies.

CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur.

In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

We generate materials in the course of our operations that may be regulated as hazardous substances.

We currently lease or operate numerous properties that have been used for oil and natural gas exploration, production and processing for many years.

Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations, where such substances have been taken for treatment or disposal.

In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or petroleum hydrocarbons was not under our control.

These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws.

Under such laws, we could be required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent future contamination, the costs of which could be substantial.

Subsurface Injections

In the course of our operations, we produce water in addition to oil and natural gas.

Water that is not recycled may be disposed of in disposal wells, which inject the produced water into non-producing subsurface formations.

Underground injection operations are regulated pursuant to the Underground Injection Control (“ UIC ”) program established under the federal SDWA and analogous state laws.

The UIC program requires permits from the EPA or an analogous state agency for the construction and operation of disposal wells, establishes minimum standards for disposal well operations, and restricts the types and quantities of fluids that may be disposed.

A change in UIC disposal well regulations or the inability to obtain permits for new disposal wells in the future may affect our ability to dispose of produced water and ultimately increase the cost of our operations.

For example, in response to recent seismic events near belowground disposal wells used for the injection of oil and natural gas-related wastewaters, regulators in some states, including Colorado, have imposed more stringent permitting and operating requirements for produced water disposal wells.

In Colorado, permit applications are reviewed specifically to evaluate seismic activity and, since 2011, the state has required operators to identify potential faults near proposed wells, if earthquakes historically occurred in the area, and to accept maximum injection pressures and volumes based on fracture gradient as conditions to permit approval.

Additionally, legal disputes may arise based on allegations that disposal well operations have caused damage to neighboring properties or otherwise violated state or federal rules regulating waste disposal.

These developments could result in additional regulation, restriction on the use of injection wells by us or by commercial disposal well vendors whom we may use from time to time to dispose of wastewater, and increased costs of compliance, which could have a material adverse effect on our capital expenditures and operating costs, financial condition, and results of operations.

In addition, the U.S.

Supreme Court’s April 2020 ruling in County of Maui, Hawaii v.

Hawaii Wildlife Fund could result in increased operational costs for the Company if permits are required under the CWA for disposal of the Company’s flowback and produced water in disposal wells, In November 2023, the EPA issued draft guidance outlining the factors that may be considered when evaluating whether discharges through groundwater may be the “functional equivalent” of a direct discharge, and thereby subject to regulation under the CWA National Pollutant Discharge Elimination System Permit Program (which permits point sources to discharge specified amounts of pollutant(s) to waters of the United States under specified conditions, and describes the types of information that should be used in determination).

The EPA held a comment period for the draft guidance in November and December 2023, but to date the EPA has not finalized any guidance, with the next steps for this guidance unclear given the January 2025 presidential transition.

Our properties located in New Mexico are subject to the authority of the New Mexico Environment Department and the Energy, Minerals and Natural Resources Department’s OCD, as well as other state agencies.

In December 2023, the New Mexico Environment Department proposed new regulations that would require the reuse of produced water generated by the oil and gas industry, so long as there is no discharge to surface or groundwater.

Public hearings commenced May 13, 2024, and a final rule is expected in 2025.

Regulation of Flowlines

Pipelines, gathering systems, and terminal operations are subject to increasingly strict safety laws and regulations.

Both the transportation and storage of refined products and crude oil involve a risk that hazardous liquids may be released into the environment, potentially causing harm to the public or the environment.

In turn, such incidents may result in substantial expenditures for response actions, significant penalties, liability for natural resources damages, and significant business interruption.

Department of Transportation has adopted safety regulations with respect to the design, construction, operation, maintenance, inspection, and management of our pipeline and storage facilities.

These regulations contain requirements for the development and implementation of pipeline integrity management programs, which include the inspection and testing of pipelines and the correction of anomalies.

These regulations also require that pipeline operation and maintenance personnel meet certain qualifications and that pipeline operators develop comprehensive spill response plans.

There have been recent initiatives to strengthen and expand pipeline safety regulations and to increase penalties for violations.

The Pipeline Safety, Regulatory Certainty, and Job Creation Act was signed into law in early 2012.

In addition, the Pipeline and Hazardous Materials Safety Administration (“ PHMSA ”) has issued new rules to strengthen federal pipeline safety enforcement programs.

In 2015, the PHMSA proposed to expand its regulations in a number of ways, including through the increased regulation of gathering lines, even in rural areas.

In 2016, the PHMSA increased its regulations to require crude oil sampling and reporting as an “offeror” (as defined under the PHMSA) and increased its civil penalty structure.

In November 2021, the PHMSA issued its final rule extending reporting requirements to all onshore gas gathering operators and applying a set of minimum safety requirements to certain onshore gas gathering pipelines with large diameters and high operating pressures.

In Colorado, on March 17, 2021, the Public Utilities Commission adopted Regulation 11 rules Regulating Pipeline Operators and Gas Pipeline Safety.

These regulations apply to all gas public utilities, all municipal or quasi-municipal corporations transporting natural gas or providing natural gas services, all operators of master meter systems, and all operators of pipelines transporting gas in intrastate commerce including gas gathering system operators (certain provisions are tailored to the location and size of the gathering systems involved).

The rules require all filed reports to be publicly available and all Notices of Proposed Violation, Notices of Action, pleadings and decisions to be filed publicly.

The rules also provide a revised methodology for calculating civil penalties in an effort to provide clarity to both operators and the public.

Global Warming and Climate Change

The EPA has published findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because such emissions are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes.

These findings provide the basis for the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the CAA.

In June 2010, the EPA began regulating GHG emissions from stationary sources.

In August 2022, then President Biden signed into law the Inflation Reduction Act of 2022.

Among other things, the Inflation Reduction Act includes a methane emissions reduction program that amends the CAA to include a Methane Emissions and Waste Reduction Incentive Program for petroleum and natural gas systems.

This program requires the EPA to impose a “waste emissions charge” on certain oil and gas sources that are already required to report under EPA’s Greenhouse Gas Reporting Program.

To implement the program, in May 2024, the EPA finalized revisions to the Greenhouse Gas Reporting Program for petroleum and natural gas facilities.

Among other things, the new rule expands the emissions events that are subject to reporting requirements to include “other large release events” and applies reporting requirements to certain new sources and sectors.

The emissions reported under the Greenhouse Gas Reporting Program will be the basis for any payments under the Methane Emissions Reduction Program.

However, petitions for reconsideration to EPA are pending and litigation in the D.C.

Circuit has commenced.

In November 2024, EPA finalized a rule to implement the Inflation Reduction Act’s Waste Emissions Charge.

The fee imposed under the Methane Emissions and Waste Reduction Incentive Program for 2024 is $900 per ton emitted over annual methane emissions thresholds, and increases to $1,200 in 2025, and $1,500 in 2026.

In January 2025, industry associations challenged the Waste Emissions Charge rule in the D.C.

The emissions fee and funding provisions of the Inflation Reduction Act could increase operating costs within the oil and gas industry and accelerate the transition away from fossil fuels, which could in turn adversely affect our business and results of operations.

However, in January 2025, President Trump issued executive orders directing an immediate pause on the disbursement of funds appropriated through the Inflation Reduction Act, and also directed withdrew the United States from the Paris Agreement and all other agreements made under the United Nations Framework Convention on Climate Change.

Consequently, future implementation and enforcement of these rules remains uncertain at this time.

In addition, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of carbon taxes, policies, and incentives to encourage the use of renewable energy or alternative low-carbon fuels, the development of greenhouse gas inventories, and cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs.

Additionally, on March 6, 2024, the SEC issued its final rule regarding the enhancement and standardization of mandatory climate-related disclosures for investors, which requires large accelerated and accelerated filers to provide climate-related disclosures in their annual reports and registration statements beginning with annual reports for the year ending December 31, 2025 for calendar-year-end filers, and beginning with annual reports for the year ending December 31, 2027 for smaller reporting companies like ours.

The final rule requires large accelerated and accelerated filers to provide Scope 1 and Scope 2 GHG emissions disclosures and more extensive GHG-related financial statement disclosure requirements.

The most stringent disclosure and reporting provisions under the SEC’s final rule do not apply to the Company as it is a smaller reporting company, but should the Company become an accelerated filer, or should future SEC rules be issued that apply such disclosure requirements on smaller reporting companies, such rules could impose significant disclosure requirements and costs on our operations.

The SEC’s Greenhouse Gas Rule is currently being challenged in litigation consolidated in the Eighth Circuit, and the SEC has stayed the effective date pending completion of that litigation.

Additionally, then SEC Acting Chair Mark Uyeda, on February 11, 2025, issued a statement saying the Greenhouse Gas Rule is flawed and directed the SEC staff to notify the Court of the changed circumstances and request that the Court not schedule the case for argument to provide time for the SEC to deliberate and determine the appropriate next steps in the case.

At this time the final outcome of the SEC’s Greenhouse Gas Rule is unknown.

We do not anticipate that such fees will have material effect on our financial condition or results of operations.

Congress may adopt additional significant legislation in the future to reduce emissions of GHGs.

In May 2019, Colorado passed GHG inventory legislation and climate action legislation.

House Bill 19-1261 concerns the reduction of GHG pollution and established statewide GHG pollution reduction goals.

Senate Bill 19-096 concerns the collection of GHG emissions data to facilitate measures to cost-effectively meet the state’s GHG emissions reduction goals established in HB 19-1261.

Regulations implementing the GHG inventory requirements of these statutes took effect on July 15, 2020.

Additionally, in January 2021, the Colorado Energy Office and Colorado Department of Public Health and Environment finalized a Greenhouse Gas Pollution Reduction Roadmap.

The GHG Roadmap lays out a pathway to meet the state’s climate action targets established in HB 19-1261, as amended by HB 21-1266.

In October 2023, the AQCC adopted the Greenhouse Gas Emissions and Energy Management for Manufacturing Phase 2 (“ GEMM 2 ”) rule, which requires 18 of Colorado’s highest emitting manufacturers in the industrial sector (which includes energy use in the oil and gas industry) to collectively reduce their GHG levels by 20% by 2030, as compared to 2015 levels.

The final rule is expected following a review of GEMM 2 by the end of 2025.

In New Mexico, as discussed above, the NMOCD has enacted methane capture rules and additional rules regulating the monitoring of emission rates, performance of enhanced checks for leaks, repair of leaks, and maintenance of records to demonstrate continuous compliance.

Regulation of methane and other GHG emissions associated with oil and natural gas production could impose significant requirements and costs on our operations.

Endangered Species and Migratory Birds Considerations

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Human Capital Resources

At December 31, 2024, we employed 14 people and also utilize the services of independent contractors to perform various field and other services.

At March 27, 2026, we employed 25 people and also utilize the services of independent contractors to perform various field and other services.

Our future success will depend partially on our ability to attract, retain and motivate qualified personnel.

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 1. Business