PEDEVCO CORP 10-K/A

ITEM 1. BUSINESS. History We were originally incorporated in September 2000 as Rocker & Spike Entertainment, Inc. In January 2001 we changed our name to Reconstruction Data Group, Inc., and in April 2003 we changed our name to Verdisys, Inc. and were engaged in the business of providing satellite services to agribusiness. In June 2005, we changed our name to Blast Energy Services, Inc. (“ Blast ”) to reflect our new focus on the energy services business, and in 2010 we changed the direction of the Company to focus on the acquisition of oil and gas producing properties. On July 27, 2012, we acquired, through a reverse acquisition, Pacific Energy Development Corp., a privately held Nevada corporation, which we refer to as Pacific Energy Development. As described below, pursuant to the acquisition, the stockholders of Pacific Energy Development gained control of approximately 95% of the then voting securities of our company. Since the transaction resulted in a change of control, Pacific Energy Development was the acquirer for accounting purposes. In connection with the merger, which we refer to as the Pacific Energy Development merger, Pacific Energy Development became our wholly-owned subsidiary and we changed our name from Blast Energy Services, Inc. to PEDEVCO Corp. 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. Our corporate headquarters are located in approximately 5,200 square feet of office space at 575 N. Dairy Ashford, Suite 210, Houston, Texas 77079. We lease that space pursuant to a lease that expires in February 2027. Business Operations Overview We are an oil and gas company focused on the acquisition and development of oil and natural gas assets where the latest in modern drilling and completion techniques and technologies have yet to be applied. 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. 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. 11 Table of Contents 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 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. · Apply modern drilling and completion techniques and technologies. We own and intend to acquire additional properties that have been historically underdeveloped and underexploited. 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. · 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. Our management and technical teams have an extensive track record of forming and building 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. · 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. 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 ”). 12 Table of Contents 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. 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. Simon G, 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. 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 .” 13 Table of Contents Competition The oil and natural gas industry is highly competitive. We compete, and will continue to compete, with major and independent oil and natural gas companies for exploration and exploitation opportunities, acreage and property acquisitions. We also compete for drilling rig contracts and other equipment and labor required to drill, operate and develop our properties. Many of our competitors have substantially greater financial resources, staffs, facilities and other resources than we have. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. These competitors may be able to pay more for drilling rigs or exploratory prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our competitors may also be able to afford to purchase and operate their own drilling rigs. Our ability to exploit, drill and explore for oil and natural gas and to acquire properties will depend upon our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. 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. Competitive Strengths We believe we are well positioned to successfully execute our business strategies and achieve our business objectives because of the following competitive strengths: Legacy Conventional Focus . Legacy conventional oil fields that have seen large-scale vertical development. Vertical production confirms moveable hydrocarbons ideal for horizontal development that may have been technologically or economically limited or missed. Technical Engineering & Operations Expertise . Lateral landing decisions incorporate log analysis, fracture-geometry modeling and an understanding of local porosity and saturation distributions. Our team are creative problem solvers with expertise in wellbore mechanics, completion design, production enhancement, artificial lift design, water handling, facilities optimization, and production down-time reduction. 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. Management . 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. 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. 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. 14 Table of Contents Our Board of Directors also brings extensive oil and gas industry experience, headed by our Executive Chairman, Dr. Simon G. 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. 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. 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. Marketing 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. 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. Oil . Our crude oil is generally sold under short-term, extendable and cancellable agreements with unaffiliated purchasers. Crude oil prices realized from production sales are indexed to published posted refinery prices, and to published crude indexes with adjustments on a contract basis. Transportation costs related to moving crude oil are also deducted from the price received for crude oil. 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. 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. 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. 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. 15 Table of Contents 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 (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. 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 ”). Our Core Areas 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. Our Permian Basin Asset was assembled through three acquisitions completed between 2018 and 2019. In the first acquisition, we acquired 100% of the assets of Hunter Oil Company, with an effective date of September 1, 2018, which created our core Permian position. 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, 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. 16 Table of Contents State of New Mexico 17 Table of Contents 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. 18 Table of Contents 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 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. 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. 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). 19 Table of Contents Weld and Morgan Counties, Colorado and Laramie County, Wyoming 20 Table of Contents Production, Sales Price and Production Costs We have listed below the total production volumes and total revenue, net to the Company, for the years ended December 31, 2024, 2023, and 2022: 2024 2023 2022 Total Revenues $ 39,553,000 $ 30,784,000 $ 30,034,000 Oil: Total Production (Bbls) 492,396 382,794 304,507 Average sales price (per Bbl) $ 73.50 $ 72.95 $ 90.86 Natural Gas: Total Production (Mcf) 608,382 479,533 245,923 Average sales price (per Mcf) $ 2.00 $ 3.00 $ 6.41 NGL: Total Production (Bbls) 78,003 58,170 19,277 Average sales price (per Bbl) $ 27.48 $ 24.43 $ 40.87 Oil Equivalents: Total Production (Boe) (1) 671,796 520,886 364,771 Average Daily Production (Boe/d) 1,835 1,427 999 Average Production Costs (per Boe) (2) $ 10.36 $ 8.98 $ 13.12 _________________________ (1) Assumes 6 Mcf of natural gas equivalents to 1 barrel of oil. (2) 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. 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): 2024 2023 2022 Oil (Boe): Chaveroo (Permian Asset Base) - 157,413 211,310 Wattenberg (D-J Asset Base) 199,518 220,788 61,031 Natural Gas (Mcf): Chaveroo (Permian Asset Base) - 66,270 - Wattenberg (D-J Asset Base) 445,650 354,570 125,196 NGL (Boe): Chaveroo (Permian Asset Base) - - - Wattenberg (D-J Asset Base) 59,842 52,013 9,788 Total Production (Boe)(1): Chaveroo (Permian Asset Base) - 168,458 211,310 Wattenberg (D-J Asset Base) 333,635 331,896 91,685 (1) Assumes 6 Mcf of natural gas equivalent to 1 barrel of oil. The following table summarizes our gross and net developed and undeveloped leasehold acreage Iat December 31, 2024: Total Developed (1) Undeveloped (2) Gross Net Gross Net Gross Net D-J Basin 82,560 18,669 69,760 11,150 12,800 7,519 Permian Basin 26,240 14,105 21,760 13,785 4,980 320 Total 108,800 32,774 91,520 24,935 17,280 7,839 (1) Developed acreage is the number of acres that are allocated or assignable to producing wells or wells capable of production. (2) Undeveloped acreage is lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage includes proved reserves. We believe we have satisfactory title, in all material respects, to substantially all of our producing properties in accordance with standards generally accepted in the oil and natural gas industry. 21 Table of Contents 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 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. Well Summary The following table presents our ownership in productive crude oil and natural gas wells at December 31, 2024. This summary includes crude oil wells in which we have a working interest: Gross Net Crude oil 117.0 59.3 Natural gas - - Total* 117.0 59.3 * Total percentage of gross operated wells is 47.0%. The Company also had royalty interests in 33 gross (0.16 net) wells. Drilling Activity We drilled wells or participated in the drilling of wells as indicated in the table below: 2024 2023 2022 Gross Net Gross Net Gross Net Development Productive 27 5.1 8 0.4 8 4.1 Dry - - - - - - Exploratory Productive - - - - - - Dry - - - - - - As of December 31, 2024, the Company had no gross or net wells in the process of being drilled, completed or waiting on completion. Oil and Natural Gas Reserves Reserve Information. For estimates of the Company’s net proved producing reserves of crude oil and natural gas, as well as discussion of the Company’s proved and probable undeveloped reserves, see “ Part II ” - “ Item 8 Financial Statements and Supplementary Data ” – “ Supplemental Oil and Gas Disclosures (Unaudited) ”. At December 31, 2024, the Company’s total estimated proved reserves were 18.1 million Boe, of which 14.2 million Bbls were crude oil and NGL reserves, and 23.4 million Mcf were natural gas reserves. Internal Controls. Arvind Krishna, our Director of Development and Reservoir Engineering (a non-executive position), is the technical person primarily responsible for our internal reserves estimation process (which is based upon the best available production, engineering and geologic data) and has in excess of five years as a reserves estimator and provides oversight of the annual audit of our year end reserves by our independent third party engineers. He has a Master of Science degree in Petroleum Engineering from The University of Texas at Austin and an MBA from Rice University. 22 Table of Contents 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. To achieve reasonable certainty, our internal reserve engineer and Cawley, Gillespie and Associates (“ Cawley ”), our independent reserve engineers, employ technologies demonstrated to yield results with consistency and repeatability. The technologies used in the estimation of our proved reserves include, but are not limited to, preparing deep dive geologic understanding of the basins, analyzing oil in place, horizontal well targeting, offset well activity, statistical analysis and correlating well performance with the geology to hi-grade locations that maximize the future value from the field. Our reserve analysis also includes, but is not limited to the following: · Comprehensive review of operators and related performance around our lease acreage. · The review of internal reserve estimates by well and by area by a qualified petroleum engineer. A variance by well to the previous year-end reserve report is used as a tool in this process. · SEC-compliant internal policies to determine and report proved reserves. · The discussion of any material reserve variances among management to ensure the best estimate of remaining reserves. Qualifications of Third-Party Engineers. The technical person primarily responsible for the audit of our reserves estimates at Cawley, Gillespie & Associates, Inc. is W. Todd Brooker, who meets the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Cawley, Gillespie & Associates, Inc. is an independent firm and does not own an interest in our properties and is not employed on a contingent fee basis. Reserve estimates are imprecise and subjective and may change at any time as additional information becomes available. Furthermore, estimates of oil and gas reserves are projections based on engineering data. There are uncertainties inherent in the interpretation of this data as well as the projection of future rates of production. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. A copy of the report issued by Cawley, Gillespie & Associates, Inc. is attached to this Report as Exhibit 99.1 . 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 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. 23 Table of Contents 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 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. 24 Table of Contents 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). 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. 25 Table of Contents 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. 704 ”). 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. Form No. 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. 552. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order No. 704. 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. 704. 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. 26 Table of Contents 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. 27 Table of Contents 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. 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. 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. 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. 28 Table of Contents 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. EPA , No. 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. Bd. of County Comm. of Weld County v. EPA , No. 21-1263. 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 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. The AQCC has undertaken a multi-year rulemaking process to implement the requirements of SB 19-181, including a rulemaking to require continuous emission monitoring equipment at oil and gas facilities. Between December 2019 and December 2020, the AQCC completed several rulemakings as a result of SB 19-181, adopting significant additional and new emission control requirements applicable to oil and gas operations, including, for example, hydrocarbon liquids unloading control requirements, increased LDAR frequencies for facilities in certain proximity to occupied areas, and emission control requirements for certain large natural gas fired engines. The AQCC conducted an additional rulemaking in December 2021 related to SB 19-181, which is discussed in further detail below. State-level rules applicable to our operations include regulations imposed by the Colorado Department of Public Health and Environment’s (“ CDPHE ”) Air Quality Control Commission, including stringent requirements relating to monitoring, recordkeeping and reporting matters. In 2020, the ECMC relied in part on a previously-performed human health risk assessment in adopting new siting requirements. The new requirements prohibit the siting of locations within 2,000 feet of a school facility or child-care center. A similar 2,000-foot setback requirement applies to residential and high occupancy building units, but there are “off ramps” allowing oil and gas operators to site their drill pads as close as 500 feet from building units in certain circumstances. The ECMC also generally prohibited the venting or flaring of natural gas during drilling, completion, and production operations. In addition, on August 30, 2022, environmental groups filed a petition for rulemaking with the ECMC, petitioning the ECMC to adopt new rules to evaluate and address the cumulative air impacts of oil and gas development in Colorado. The petition proposes to address the cumulative air impacts of oil and gas development by effectively prohibiting any oil and gas project located in an area where the air quality exceeds, or may exceed, applicable air quality standards. 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. 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. 29 Table of Contents 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. AQCC is expected to undertake several rulemaking efforts to further reduce emissions in the next several years. 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. 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. Commencing April 1, 2022, operators are required to reduce the annual volume of vented and flared natural gas in order to capture no less than ninety-eight percent of the natural gas produced from all wells by December 31, 2026 (New Mexico Administrative Code Section 19.15.27.9). This rule change is accompanied by additional reporting requirements for all flared and vented gas. 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 (“ NMOCD ”) 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. 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. 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. As a result, future implementation and enforcement of this rule remains uncertain at this time. 30 Table of Contents 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. 31 Table of Contents 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. Other State Laws At the state level, Colorado, where we conduct significant operations, is among the states that has adopted, and other states are considering adopting, regulations that could impose new or more stringent permitting, disclosure or well-construction requirements on hydraulic fracturing operations. Moreover, states could elect to prohibit high volume hydraulic fracturing altogether, following the approach taken by the State of New York in 2015. Also, certain interest groups in Colorado opposed to oil and natural gas development generally, and hydraulic fracturing in particular, have from time-to-time advanced various options for ballot initiatives that, if approved, would allow revisions to the state constitution in a manner that would make such exploration and production activities in the state more difficult in the future. However, during the November 2016 voting process, one proposed amendment placed on the Colorado state ballot making it relatively more difficult to place an initiative on the state ballot was passed by the voters. As a result, there are more stringent procedures now in place for placing an initiative on a state ballot. In addition to state laws, local land use restrictions may restrict drilling or the hydraulic fracturing process and cities may adopt local ordinances allowing hydraulic fracturing activities within their jurisdictions but regulating the time, place and manner of those activities. For example, on November 6, 2018, registered voters in the State of Colorado cast their ballots and rejected Proposition 112 (“ Prop. 112 ”), with 55% of ballots cast against the measure. Prop. 112 would have created a rigid 2,500-foot setback from oil and gas facilities to the nearest occupied structure and other “vulnerable areas,” which included parks, ball fields, open space, streams, lakes and intermittent streams. 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. 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. The authors of the legislation were clear that SB 19-181 was not intended to allow an outright ban on oil and gas development. However, anti-industry activists in Longmont, Colorado, have argued in court that SB 19-181 permits a local governmental authority to impose such a ban. 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 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. We anticipate that the ECMC, the Conservation Division of the New Mexico Energy, Minerals, Natural Resources Department, the New Mexico State Land Office, the New Mexico Environment Department and other federal, state and local authorities will continue to adopt new rules and regulations moving forward which will likely affect our oil and gas operations and could make it more costly for our operations or limit our activities. We routinely monitor our operations and new rules and regulations which may affect our operations, to ensure that we maintain compliance. 32 Table of Contents 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. 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 costs 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. In the event that local or state restrictions or prohibitions are adopted in areas where we conduct operations, that impose more stringent limitations on the production and development of oil and natural gas, including, among other things, the development of increased setback distances, we and similarly situated oil and natural exploration and production operators in the state 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 and similarly situated operates 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. 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. 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. 33 Table of Contents 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. 34 Table of Contents 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. The U.S. 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. 35 Table of Contents 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. Circuit. 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. 36 Table of Contents 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. 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. 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 The federal Endangered Species Act (“ ESA ”), and comparable state laws were established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species or that species’ habitat. Similar protections are offered to migrating birds under the Migratory Bird Treaty Act. We may conduct operations on oil and natural gas leases in areas where certain species that are listed as threatened or endangered are known to exist, including the lesser prairie chicken which is now considered endangered as of November 2022, and where other species that potentially could be listed as threatened or endangered under the ESA may exist. Moreover, as a result of one or more agreements entered into by the U.S. Fish and Wildlife Service, the agency is required to make a determination on listing of numerous species as endangered or threatened under the ESA pursuant to specific timelines. The identification or designation of the lesser prairie chicken as endangered, and previously unprotected species as threatened or endangered, in areas where underlying property operations are conducted, could cause us to incur increased costs arising from species protection measures, time delays or limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce reserves. Currently, all net acres in our Permian Basin Asset have been designated as critical or suitable habitat for the lesser prairie chicken, which could adversely impact the pace of our development and the value of these leases. 37 Table of Contents Other We are also subject to rules regarding worker safety and similar matters promulgated by the U.S. Occupational Safety and Health Administration (“ OSHA ”) and other governmental authorities. OSHA has established workplace safety standards that provide guidelines for maintaining a safe workplace in light of potential hazards, such as employee exposure to hazardous substances. To this end, OSHA adopted a new rule governing employee exposure to silica, including during hydraulic fracturing activities, in March 2016. 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 Lawsuits have been filed against other operators in several states, including Colorado, alleging contamination of drinking water as a result of hydraulic fracturing activities. Should private litigation be initiated against us, it could result in injunctions halting our development and production operations, thereby reducing our cashflow from operations, and incurrence of costs and expenses to defend any such litigation. Related Permits and Authorizations Many environmental laws require us to obtain permits or other authorizations from state and/or federal agencies before initiating certain drilling, construction, production, operation, or other oil and natural gas activities, and to maintain these permits and compliance with their requirements for on-going operations. These permits are generally subject to protest, appeal, or litigation, which can in certain cases delay or halt projects and cease production or operation of wells, pipelines, and other operations. We are not able to predict the timing, scope and effect of any currently proposed or future laws or regulations regarding hydraulic fracturing, but the direct and indirect costs of such laws and regulations (if enacted) could materially and adversely affect our business, financial conditions and results of operations. See further discussion in “ Part I ” – “ Item 1A. Risk Factors .” Insurance Our oil and gas properties are subject to hazards inherent in the oil and gas industry, such as accidents, blowouts, explosions, implosions, fires and oil spills. These conditions can cause: · damage to or destruction of property, equipment and the environment; · personal injury or loss of life; and · suspension of operations. We maintain insurance coverage that we believe to be customary in the industry against these types of hazards. However, we may not be able to maintain adequate insurance in the future at rates we consider reasonable. In addition, our insurance is subject to coverage limits and some policies exclude coverage for damages resulting from environmental contamination. The occurrence of a significant event or adverse claim in excess of the insurance coverage that we maintain or that is not covered by insurance could have a material adverse effect on our financial condition and results of operations. 38 Table of Contents 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. Our future success will depend partially on our ability to attract, retain and motivate qualified personnel. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We consider our relations with our employees to be satisfactory. The development, attraction and retention of employees is a critical success factor for the Company. To support the advancement and education of our employees, we offer training and development programs to our employees, including training on compliance, general business, management, harassment prevention, leadership, and workplace safety-related topics to further their personal and professional development. We also require annual anti-harassment training of all employees and supervisors. We also offer our employees competitive pay and benefits. The Company’s compensation programs are designed to align the compensation of our employees with the Company’s performance and to provide the proper incentives to attract, retain and motivate employees to achieve superior results. The structure of our compensation programs balances incentive earnings for both short-term and long-term performance. Specifically: · We provide employee wages that are competitive and consistent with employee positions, skill levels, experience, knowledge and geographic location. · Annual increases and incentive compensation are based on merit, which is communicated to employees at the time of hiring and documented through our annual review procedures and upon internal transfer and/or promotion. · All employees are eligible for health insurance, paid and unpaid leaves, a retirement plan and life and disability/accident coverage. We also offer a variety of voluntary benefits that allow employees to select the options that meet their needs, including flexible spending accounts, flexible time-off, telemedicine, wellness resources, legal resources and identity protection plans, family leave, and adoption assistance, among others. Available Information The Company’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to reports filed pursuant to Sections 13(a) and 15(d) of the Exchange Act. Such reports and other information filed by the Company with the SEC are available free of charge at https://www.pedevco.com/sec-filings when such reports are available on the SEC’s website. The Company periodically provides other information for investors on its corporate website, www.pedevco.com . This includes press releases and other information. The information contained on the websites referenced in this Annual Report is not incorporated by reference into this filing. Further, the Company’s references to website URLs are intended to be inactive textual references only. 39 Table of Contents