What changed in this filing

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Item 1. Business

2025-03-31 compared with 2024-03-18 · 148 added, 130 removed, 536 unchanged (34% of the section changed)

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(“ 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, 2023, we held approximately 19,214 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, 2023, we held interests in 300 gross and net wells in our Permian Basin Asset, of which 25 are active producers, two are active injectors and two are active salt water disposal wells (“ SWD’ s”), all of which are held by PEDCO and operated by RAZO, and interests in 98 gross (24.6 net) wells in our D-J Basin Asset held by PRH, all of which 18 gross (16.2 net) wells are operated by Red Hawk and currently producing, 63 gross (8.4 net) wells are non-operated, and 17 wells have an after-payout interest.

(“ 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.

Business Strategy

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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.

Maintain a high degree of operational control.

We believe that by retaining high operational control, we can efficiently manage the timing and amount of our capital expenditures and operating costs, and thus key in on the optimal drilling and completions strategies, which we believe will generate higher recoveries and greater rates of return per well.

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

We believe that by retaining operational control and/or by forming partnerships which require consent and input by all partners in major development projects, we can efficiently manage the timing and amount of our capital expenditures and operating costs, and thus key in on the optimal drilling and completions strategies, which we believe will generate higher recoveries and greater rates of return per well.

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

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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.

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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 held by production (“ HBP ”), allowing for flexibility of timing on development.

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.

Our 2025 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 Chief Executive Officer and director, which funding Dr.

Kukes is under no obligation to provide, and (iv) funding through credit or loan facilities.

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).

In addition, we may seek additional funding through asset sales, farm-out arrangements, and credit facilities to fund potential acquisitions during the remainder of 2025.

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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 our Chief Executive Officer, Dr.

Kukes, who was formerly 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 Chairman of Yukos Oil Company.

Our President, J.

Douglas Schick, 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.

In addition, our Executive Vice President and General Counsel, Clark R.

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.

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.

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.

Several other members of the management and operations teams have also successfully helped develop similar companies with like kind asset profiles and technical operations in the Permian Basin and elsewhere in the United States.

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 Chairman, John J.

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.

In addition, our Board includes H.

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.

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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 a nominal 1% of our total revenues as of December 31, 2023, and the Company believes that this trend will continue in the D-J Basin Asset.

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.

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.

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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 $17 million to $20 million for drilling and completion costs on our Permian Basin and D-J Basin Asset and approximately $3 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 (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.

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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 300 gross and net wells, of which 25 wells are active producers, two wells are active injectors, and two are active SWDs.

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, 2024, 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

The San Andres oilfields of the Northwest Shelf, Central Basin Platform and the Eastern Shelf are some of the largest oilfields within the Permian Basin.

According to the U.S.

Energy Information Administration (“ EIA ”), as of December 31, 2013, three oil fields that have produced from the San Andres formation were amongst the top 50 largest oilfields by reserves in the United States.

The San Andres has been historically under-developed due to technological and economic limitations during early development.

The San Andres is a dolomitic carbonate reservoir characterized as being highly-heterogenous with a multi-porosity system that typically shows significant oil saturation, but primary production often yields higher than normal water cut.

While existing San Andres operators may ascribe different drivers for the water cut, San Andres production requires sufficient fluid removal, transportation and disposal, in order to achieve higher oil cuts, through a network of on-site fluid storage and saltwater disposal systems.

Oil was originally trapped in the San Andres by three types of pre-Tertiary traps:

Structural, Stratigraphic and Structurally enhanced Stratigraphic.

Legacy fields exist where oil accumulated in these traps to form thick oil columns, referred to as Main Pay Zones (“ MPZ ”).

Legacy San Andres fields lack sharp oil-water contacts creating secondary zones of increasing water saturation beneath the MPZ known as Transitional Oil Zones (“ TOZ ”) and Residual Oil Zones (“ ROZ ”).

TOZs and ROZs also extend outside the historical boundaries of the legacy fields downdip to their structural limits.

The vast majority of horizontal San Andres wells have been drilled in these TOZ and ROZ areas where vertical development is uneconomic.

In September 2023, the Company and Evolution Petroleum Corporation (“ Evolution ”) entered into a 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 ”).

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:

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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.

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.

The SFO superseded all previous Agreed Compliance Orders, as amended, entered into by and between RAZO and the OCD.

We believe that the Company’s 22,721 net acres within the Chaveroo Field offer a unique opportunity to drill infill horizontal wells targeting the higher oil-saturations of the MPZs.

We believe that the Company’s approximately 14,550 net acres within the Chaveroo and Chaveroo NE Fields offer a unique opportunity to drill infill horizontal wells.

The Chaveroo NE Field is an extension of the Chaveroo Field that was not originally developed vertically.

There are currently 300 wellbores within the leasehold, of which 25 are active producers and two are active injectors, and two are active SWDs.

The remainder are shut-in wellbores with future potential utility for additional water injection, production reactivations, and behind-pipe recompletions.

We currently own and operate three water handling facilities, one in each field, that have a current combined capacity of approximately 60,000 barrels of water per day (bbl/d).

D-J Basin Asset

We have grown our legacy D-J Basin Asset position to 14,283 net acres in Weld and Morgan Counties, Colorado and 4,931 net acres in Laramie County, Wyoming.

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.

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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.

(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).

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

As of December 31, 2023 and 2022, the Chaveroo and the Wattenberg fields and as of December 31, 2021, the Chaveroo, Milnesand and Wattenberg fields are the fields that each comprise 15% or more of our total proved reserves.

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.

The applicable production volumes from these fields for the years ended December 31, 2024, 2023, and 2022, are represented in the table below in total barrels (Bbls):

Chaveroo (Permian Asset Base)

Milnesand (Permian Asset Base)

Wattenberg (D-J Asset Base)

The following table summarizes our gross and net developed and undeveloped leasehold and mineral fee acreage at December 31, 2023:

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

Developed (1)

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Total Net Undeveloped Acreage Expiration

In the event that production is not established or we take no action to extend or renew the terms of our leases, our net undeveloped acreage that will expire over the next three years as of December 31, 2023, is 40, 1,721, and 4,108 for the years ending December 31, 2024, 2025 and 2026, respectively, and 2,376 net acres thereafter.

In the event that production is not established or we take no action to extend or renew the terms of our leases, our net undeveloped acreage that will expire over the next three years as follows:

(i) in the D-J Basin Asset, 809 net acres are set to expire during 2025 (net to our direct ownership interest only), with 3,662 and 1,657 net acres set to expire for the years ending December 31, 2026 and 2027 respectively, and 508.53 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.

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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, 2023, 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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He has a Master of Science degree in Petroleum Engineering from The University of Texas at Austin and an MBA from Rice University.

The preparation of our reserve estimates is in accordance with our prescribed procedures that include verification of input data into a reserve forecasting and economic software, as well as management review.

The preparation of our reserve estimates is in accordance with our prescribed procedures that include verification of input data into reserve forecasting and economic software, as well as management review.

Our reserve analysis includes, but is not limited to, the following:

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Current Year Events

Sale of EOR Operating Company and Related Non-Core Permian Basin Assets

On November 9, 2023, the Company sold certain oil and gas assets, including 8,035 acres and 80 wells in the non-core Milnesand and Sawyer fields, Permian Basin, New Mexico (the EOR Operating Company “ EOR ”, a PEDEVCO subsidiary), to Tilloo Exploration and Production LLC (“ Tilloo Exploration ”) for $1.12 million, via a five-year secured promissory note with 10% annual interest and no payments for the first year.

The sale not only eliminated the Company’s costly obligation to plug and abandon inactive wells in those fields of approximately $3.2 million(gross), but also freed up resources to focus on its core assets in Chaveroo Field of the Permian Basin and the D-J Basin.

In the transaction, Tilloo Exploration also assumed EOR's pending litigation matters and the Company retains the use of the Milnesand field office through December 2024.

As a result of this transaction, the Company strategically reduced its liabilities and can better concentrate on maximizing value from its key assets.

Drilling and Completion and Leasing Activities

For the year ended December 31, 2023, the Company incurred $27,277,000 of capital costs.

These costs were primarily related to:

drilling operations, completion and facility construction for the three new wells being jointly developed with Evolution under our Chaveroo Farmout Transaction which we started in the fourth quarter of 2023, in our Permian Basin Asset, accounting for approximately $4.5 million;

approximately $5.6 million relating to production enhancement cleanouts in our Permian Basin Asset;

and approximately $11.2 million for the development of assets in the D-J Basin, which also includes our participation in the drilling and completion of thirteen wells by a third-party operator in the latter part of the period that are expected to begin production in early 2024.

The Company also acquired approximately 282 net mineral acres, and 6,465 net lease acres, in and around its existing footprint in the D-J Basin through multiple transactions with total acquisition and due diligence costs of $493,000 for the net mineral acres and $5,211,000 for the net lease acres.

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 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.

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.

Regulation of the Oil and Gas Industry

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Federal Air Regulation

In June 2016, the EPA implemented new requirements focused on achieving additional methane and volatile organic compound reductions from the oil and natural gas industry.

The rules imposed, among other things, new requirements for leak detection and repair, control requirements for oil well completions, replacement of certain pneumatic pumps and controllers and additional control requirements for gathering, boosting and compressor stations.

On November 15, 2021, the EPA published a proposed rule that would update and expand existing requirements for the oil and gas industry, as well as creating significant new requirements and standards for new, modified, and existing oil and gas facilities.

The proposed new requirements would include, for example, new standards and emission limitations applicable to storage vessels, well liquids unloading, pneumatic controllers, and flaring of natural gas at both new and existing facilities.

In November 2022, the EPA published a supplemental proposal to update, strengthen, and expand the standards proposed in November 2021.

The EPA announced the final rule on December 2, 2023, which, among other things, requires the phase out of routine flaring of natural gas from new oil wells and routine leak monitoring at all well sites and compressor stations.

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.

The final emissions guidelines under Subpart OOOOc provide three years from the plan submission deadline for existing sources to comply.

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.

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 ”).

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18-1203, in which the D.C.

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

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.

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Circuit, and the D.C.

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

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

of County Comm.

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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 BLM published a proposed rule that would regulate venting, flaring and leaks during oil and gas production activities on federal and Indian leases.

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;

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however, the COGCC 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:

(i) in August 2024, the ECMC proposed regulations aimed at assessing and mitigating the cumulative effects of oil and gas operations, particularly in communities disproportionately impacted by environmental burdens, which rules are now in place as of December 15, 2024;

and (ii) in April 2022, the ECMC implemented new financial assurance rules mandating that oil and gas operators provide adequate funds to cover well plugging and site reclamation.

AQCC rulemakings are intended to further Colorado’s legislative directive to reduce carbon dioxide, methane and other greenhouse gases (“ GHGs ”) emissions to attain climate action goals.

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For example, in October 2023, the AQCC adopted the Greenhouse Gas Emissions and Energy Management for Manufacturing Phase 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 to take effect in 2024.

In 2021, the State of New Mexico Energy, Minerals and Natural Resources Department (“ ENMRD ”) enacted rule changes aimed at mitigating volumes of flared and vented natural gas.

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We expect to meet or exceed the required gas capture requirements in accordance with this rule change.

In addition, the New Mexico state legislature is considering a bill that would increase fines and fees on oil and gas operators and codify New Mexico’s 98% methane capture rule, which the New Mexico Energy, Minerals and Natural Resources Department enacted in 2021.

Under the methane capture rule, oil and gas operators are required to capture 98% of their produced natural gas by December 31, 2026, and routine venting and flaring is prohibited.

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.

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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 (“ 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 is not excluded.

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.

Federal agencies have periodically considered additional regulation of hydraulic fracturing.

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

On November 30, 2022, the BLM also issued a proposed rule to reduce the waste of natural gas from venting, flaring and leaks during oil and gas production activities on Federal and Indian leases.

Future litigation regarding the rules, and any alternative future rule therefore creates some uncertainty as to how BLM’s regulation of venting and flaring will impact our business.

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 ”).

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

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 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 NEPA’s implementing regulations to make the NEPA process more efficient, effective, and timely.

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).

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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.

A final rule is expected in April 2024.

The CEQ’s proposed changes could result in increased NEPA review timelines for projects involving agency action regarding federal lands, federal money, or federal permits or approvals.

We currently have limited exploration, development and production activities on federal lands, and our future exploration, development and production activities may include leasing and development of federal mineral interests, which will require the acquisition of governmental permits or authorizations that are subject to the 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.

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 subsequently announced that his administration will resume onshore oil and gas lease sales on federal lands effective April 18, 2022.

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.

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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.

We cannot assure that any such outcome would not be material, and any such outcome could have a material and adverse impact on our cash flows and results of operations.

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

Other State Laws

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It would have dramatically increased the amount of surface area off-limits to new energy development by 26 times and put 94% of private land in the top five oil and gas producing counties in the State of Colorado off-limits to new development.

See further discussion in “ Part I ” – “Item 1A.

Risk Factors.” It is possible that future ballot initiatives will be proposed that could limit the areas of the state in which drilling would be permitted to occur or otherwise impose increased regulations on our industry.

It is possible that future ballot initiatives will be proposed that could limit the areas of the state in which drilling would be permitted to occur or otherwise impose increased regulations on our industry.

Passed in Colorado in 2019, SB 19-181 gives local governmental authorities increased authority to regulate oil and gas development.

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We primarily operate in the rural areas of the Wattenberg Field in Weld and Morgan Counties, jurisdictions in which there has historically been significant support for the oil and gas industry.

In addition, on September 28, 2020, the COGCC (now the ECMC) voted in favor of a preliminary approval establishing a new 2,000-foot setback rule from buildings for drilling and fracturing operations statewide, increasing the previous 500-foot setback rule, which rule became effective January 1, 2021, and could likewise make it more difficult for us to undertake oil and gas development activities in Colorado, although given the distance of most of our current leases from buildings in Colorado, these setback rules have not yet had a significant impact on our operations, but may impact future development if we seek develop acreage within such setback boundaries.

Further, on May 10, 2022, the Colorado Legislature adopted SB 22-198, the “Orphaned Oil and Gas Well Enterprise” bill, which requires each oil and gas operator in Colorado to pay a mitigation fee to the “enterprise” for each well that has been spud but not yet plugged and abandoned.

The ECMC submitted a notice of rulemaking on May 18, 2022, to implement SB 22-198 by amending the ECMC’s annual registration fee rules to now require that an operator’s annual registration fee be paid to the enterprise as a “mitigation fee.” In addition, the newly established “Enterprise Board” now has the authority to adjust the dollar amount of the mitigation fee.

The ECMC submitted a notice of rulemaking on May 18, 2022, to implement SB 22-198 by amending the ECMC’s annual registration fee rules to require that an operator’s annual registration fee be paid to the enterprise as a “mitigation fee.” In addition, the newly established “Enterprise Board” now has the authority to adjust the dollar amount of the mitigation fee.

The amendments became effective on June 30, 2022, and may increase the registration fees required for current and future oil and gas wells in Colorado.

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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.

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.

The SFO superseded all previous Agreed Compliance Orders, as amended, entered into by and between RAZO and the OCD.

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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.

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 EPA and USACE issued a final rule to conform the WOTUS definition to the U.S.

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, EPA and USACE implemented a narrower definition of WOTUS by, for example, removing “interstate wetlands”;

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”;

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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 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 RCRA and, instead, are regulated under RCRA’s less stringent non-hazardous waste provisions, state laws or other federal laws.

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.

In December 2016, the U.S.

District Court for the District of Columbia approved a consent decree between the EPA and a coalition of environmental groups.

The consent decree requires the EPA to review and determine whether it will revise the RCRA regulations for exploration and production waste to treat such waste as hazardous waste.

In April 2019, the EPA, pursuant to the consent decree, determined that revision of the regulations was not necessary.

Information comprising the EPA’s review and decision is contained in a document entitled “Management of Exploration, Development and Production Wastes:

Factors Informing a Decision on the Need for Regulatory Action”.

The EPA indicated that it will continue to work with states and other organizations to identify areas for continued improvement and to address emerging issues to ensure that exploration, development and production wastes continue to be managed in a manner that is protective of human health and the environment.

Environmental groups, however, expressed dissatisfaction with the EPA’s decision and will likely continue to press the issue at the federal and state levels.

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.

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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 Safe Drinking Water Act (“ SDWA ”) and analogous state laws.

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.

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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.

On November 20, 2023, 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).

Comments on the draft guidance were due to the agency by December 27, 2023, and to date EPA has not finalized the guidance.

Supreme Court’s 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 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

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

In 2015, 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, 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, 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 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.

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

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

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.

In order to implement the program, the Inflation Reduction Act required revisions to GHG reporting regulations for petroleum and natural gas systems (Subpart W) by 2024.

In July 2023, the EPA proposed to expand the scope of the Greenhouse Gas Reporting Program for petroleum and natural gas facilities, as required by the Inflation Reduction Act.

Among other things, the proposed 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 rule is currently scheduled to be finalized in the spring of 2024 and would take effect on January 1, 2025, in advance of the deadline for GHG reporting for 2024 (March 2025).

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

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.

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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.

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

Since 2014, Colorado has engaged in multiple rulemakings to adopt significant additional rules regulating methane emissions from the oil and gas sector, and Colorado is expected to continue these efforts over the next several years.

In response to Colorado General Assembly House Bill 19-1261, which established statewide greenhouse gas reduction targets in Colorado, on September 30, 2020, Colorado released a public comment draft of its Greenhouse Gas Pollution Reduction Roadmap, which details early action steps the state can take toward meeting the near-term goals of reducing GHG pollution by 26% by 2025 and 50% by 2030 from 2005 levels.

On October 23, 2020, the AQCC issued the Resolution to Ensure Greenhouse Gas Reduction Goals Are Met in support of the roadmap, which estimates emission reductions needed from the oil and gas sector of 36% by 2025 and 50% by 2030.

The adopted regulatory requirements include, for example, more frequent fugitive emissions monitoring, a statewide GHG intensity program, emission limitations for well liquids unloading, and comprehensive testing of emission control devices.

Additionally, on September 30, 2020, the Colorado Energy Office and Colorado Department of Public Health and Environment finalized a Greenhouse Gas Pollution Reduction Roadmap in January 2021.

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 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 to take effect in 2024.

In New Mexico, the state legislature is considering a bill that would increase fines and fees on oil and gas operators and codify New Mexico’s 98% methane capture rule, which the New Mexico Energy, Minerals and Natural Resources Department enacted in 2021.

Under the methane capture rule, oil and gas operators are required to capture 98% of their produced natural gas by December 31, 2026, and routine venting and flaring is prohibited.

Internationally, in April 2021, President Biden announced that the United States would aim to cut its greenhouse gas emissions 50 percent to 52 percent below 2005 levels by 2030.

This commitment will be part of the United States’ “nationally determined contribution,” or NDC, to the Paris Climate Agreement.

The NDC will commit the United States to a voluntary GHG emission reduction target and outline domestic climate mitigation measures to achieve that target.

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.

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To this end, OSHA adopted a new rule governing employee exposure to silica, including during hydraulic fracturing activities, in March 2016.

Democratic control of the House, Senate and White House could lead to increased regulatory oversight and increased regulation and legislation, particularly around oil and gas development on federal lands, climate impacts and taxes.

Republican control of the House, Senate and White House could lead to decreased regulatory oversight and decreased regulation and legislation, particularly around oil and gas development on federal lands, climate impacts and taxes.

Private Lawsuits

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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