PEDEVCO CORP 10-K

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 August 2023. 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. As of December 31, 2022, we held approximately 31,308 net Permian Basin acres located in Chaves and Roosevelt Counties, New Mexico, through our wholly-owned operating subsidiary, Pacific Energy Development Corp. (“ PEDCO ”), which we refer to as our “ Permian Basin Asset, ” and approximately 12,372 net D-J Basin acres located in Weld and Morgan Counties, Colorado, through 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, 2022, we held interests in 381 gross (377 net) wells in our Permian Basin Asset, of which 42 are active producers, 16 are active injectors and two are active salt water disposal wells (“ SWD’ s”), all of which are held by PEDCO and operated by its wholly-owned operating subsidiaries, and interests in 92 gross (24.1 net) wells in our D-J Basin Asset, of which 18 gross (16.2 net) wells are operated by Red Hawk and currently producing, 53 gross (7.9 net) wells are non-operated, and 21 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. 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 have identified approximately 150 gross drilling locations across our Permian Basin acreage. 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. 7 Table of Contents · 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. We believe that by retaining high operational control, we can efficiently manage the timing and amount of our capital expenditures and operating costs, and thus key in on the optimal drilling and completions strategies, which we believe will generate higher recoveries and greater rates of return per well. · 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 us 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. 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 estimated net capital expenditures for 2023 are estimated at the time of this Annual Report to range between $25 million to $35 million. This estimate includes a range of $23 million to $33 million for drilling and completion costs on our Permian Basin and D-J Basin Assets and approximately $2 million in estimated capital expenditures for ESP purchases, rod pump conversions, recompletions, well cleanouts, leasing, facilities, remediation and other miscellaneous capital expenses. This estimate does not include anything 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 “). We plan to continue to evaluate D-J Basin well proposals as received from third party operators and participate in those we deem most economic and prospective. If new proposals are received that meet our economic thresholds and require material capital expenditures, we have flexibility to move capital from our Permian Asset to our D-J Basin Asset, or vice versa, as our Permian Asset is 100% operated and held by production (“ HBP ”), allowing for flexibility of timing on development. Our 2023 development program incorporates service costs that have remained relatively flat, based on costs we have experienced since the third quarter of 2022. Our 2023 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. 8 Table of Contents 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 2023 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 Kukes, our Chief Executive Officer and director, which funding Dr. Kukes is under no obligation to provide, (iv) public or private debt or equity financings, including up to $3.5 million in securities which we may sell in the future in an on-going “at the market offering”, subject to availability under the Company’s shelf-registration, which limits the maximum amount of securities which can be sold in any 12 month period to 1/3 of the Company’s then public float, and (v) funding through credit or loan facilities. In addition, we may seek additional funding through asset sales, farm-out arrangements, and credit facilities to fund potential acquisitions during the remainder of 2023. The following chart reflects our current organizational structure: *Represents percentage of total voting power based on 87,040,267 shares of common stock outstanding as of March 29, 2023, 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 . ” 9 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 our Chief Executive Officer, Dr. Simon Kukes, who was formerly the CEO at Samara-Nafta, a joint venture with the U.S.-based international oil company Hess Corporation, CEO of Tyumen Oil Company (TNK), prior to its combination with British Petroleum, and Chairman of Yukos Oil Company. Our President, J. Douglas Schick, has over 25 years of experience in the oil and gas industry, having co-founded American Resources, Inc., and formerly serving in executive, management and operational planning, strategy and finance roles at Highland Oil and Gas, Mariner Energy, Inc., The Houston Exploration Co., ConocoPhillips and Shell Oil Company. In addition, our Executive Vice President and General Counsel, Clark R. Moore, has nearly 20 years of energy industry experience, and formerly served as acting general counsel of Erin Energy Corp. Several other members of the management and operations teams have also successfully helped develop similar companies with like kind asset profiles and technical operations in the Permian Basin and elsewhere in the United States. We believe that our management team is highly qualified to identify, acquire and exploit energy resources in the U.S. Our board of directors also brings extensive oil and gas industry experience, headed by our Chairman, John J. Scelfo, who brings over 40 years of experience in oil and gas management, finance and accounting, and who served in numerous executive-level capacities at Hess Corporation, including as Senior Vice President, Finance and Corporate Development, Chief Financial Officer, Worldwide Exploration & Producing, and as a member of Hess’ Executive Committee. In addition, our Board includes Ivar Siem, who brings over 50 years of broad experience from both the upstream and the service segments of the oil and gas industry, including serving as Chairman of Blue Dolphin Energy Company (OTCQX: BDCO), as Chairman and interim CEO of DI Industries/Grey Wolf Drilling, as Chairman and CEO of Seateam Technology ASA, and in various executive roles at multiple oil and gas exploration and production (E&P) and oil field service companies. Furthermore, our Board 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. 10 Table of Contents Significant acreage positions and drilling potential . As of December 31, 2022, we have accumulated interests in a total of 31,308 net acres in our core Permian Basin Asset operating area, and 12,372 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 150 potential net wells, comprised of 135 net 1.0-mile lateral wells and 15 net 1.5-mile lateral wells, on 160-acre spacing and 240-acre spacing, respectively. We believe our D-J Basin Asset could contain up to 204 potential gross wells with 79 potential net wells, comprised of 52 gross 1.0-mile lateral wells with 20 net 1.0-mile lateral wells, 12 gross 1.5-mile lateral wells with 6 net 1.5 mile lateral wells, 140 gross 2.0-mile lateral wells with 53 net 2.0 mile lateral wells, on 80-acre spacing, 120-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, 2022, sales to two customers comprised 63% and 20%, 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 a nominal 1% of our total revenues as of December 31, 2022, 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 County, Colorado 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. Our estimated net capital expenditures for 2023 are estimated at the time of this Annual Report to range between $25 million to $35 million. This estimate includes a range of $23 million to $33 million for drilling and completion costs on our Permian Basin and D-J Basin Asset and approximately $2 million in estimated capital expenditures for ESP purchases, rod pump conversions, recompletions, well cleanouts, leasing, facilities, remediation and other miscellaneous capital expenses. This estimate does not include anything 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 ”). 11 Table of Contents Our Core Areas Permian Basin Asset We hold our Permian Basin Assets through our wholly-owned subsidiary, PEDCO, with operations conducted through PEDCO’s wholly-owned operating subsidiaries, EOR Operating Company and Ridgeway Arizona Oil Corp. 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. These interests are all located in Chaves and Roosevelt Counties, New Mexico, where we currently operate 381 gross (377 net) wells, of which 42 wells are active producers, 16 wells are active injectors, and two are active SWDs. As of December 31, 2022, our Permian Basin Asset acreage is located where indicated in the below map of the State of New Mexico and more specifically in the areas shaded in yellow in the subsequent sectional map. State of New Mexico 12 Table of Contents The San Andres oilfields of the Northwest Shelf, Central Basin Platform and the Eastern Shelf are some of the largest oilfields within the Permian Basin. According to the U.S. Energy Information Administration (“ EIA ”), as of December 31, 2013, three oil fields that have produced from the San Andres formation were amongst the top 50 largest oilfields by reserves in the United States. The San Andres has been historically under-developed due to technological and economic limitations during early development. The San Andres is a dolomitic carbonate reservoir characterized as being highly-heterogenous with a multi-porosity system that typically shows significant oil saturation, but primary production often yields higher than normal water cut. While existing San Andres operators may ascribe different drivers for the water cut, San Andres production requires sufficient fluid removal, transportation and disposal, in order to achieve higher oil cuts, through a network of on-site fluid storage and salt water disposal systems. Oil was originally trapped in the San Andres by three types of pre-Tertiary traps: Structural, Stratigraphic and Structurally enhanced Stratigraphic. Legacy fields exist where oil accumulated in these traps to form thick oil columns, referred to as Main Pay Zones (“ MPZ ”). Legacy San Andres fields lack sharp oil-water contacts creating secondary zones of increasing water saturation beneath the MPZ known as Transitional Oil Zones (“ TOZ ”) and Residual Oil Zones (“ ROZ ”). TOZs and ROZs also extend outside the historical boundaries of the legacy fields downdip to their structural limits. The vast majority of horizontal San Andres wells have been drilled in these TOZ and ROZ areas where vertical development is uneconomic. We believe that the Company’s 31,380 net acres within the Chaveroo and Milnesand fields of Chaves and Roosevelt Counties, New Mexico offer a unique opportunity to drill infill horizontal wells targeting the higher oil-saturations of the MPZs. The Chaveroo NE field is an extension of the Chaveroo field that was not originally developed vertically. There are currently 381 wellbores within the leasehold, of which 42 are active producers and 16 are active injectors, and two are active SWDs. The remainder are shut-in wellbores with future potential utility for additional water injection, production reactivations, and behind-pipe recompletions. We currently own and operate three water handling facilities, one in each field, that have a current combined capacity of approximately 60,000 barrels of water per day (bbl/d). 13 Table of Contents D-J Basin Asset We have grown our legacy D-J Basin Asset position to 12,372 net acres in Weld and Morgan Counties, Colorado. We directly hold all of our interests in the D-J Basin Asset through our wholly-owned subsidiary, Red Hawk. These interests are all located in Weld and Morgan Counties, Colorado. Red Hawk has an interest in 92 gross (24.1 net) wells and is currently the operator of 18 gross (16.2 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), 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. Other active operators in the area include Fundare Resources Company, LLC (which acquired Whiting Petroleum Company’s D-J Basin interests in late 2019), Occidental Petroleum (which acquired Anadarko Petroleum in 2019) and PDC Energy (which acquired SRC Energy in 2019). Weld and Morgan Counties, Colorado 14 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, 2022, 2021, and 2020: 2022 2021 2020 Total Revenues $ 30,034,000 $ 15,860,000 $ 8,059,000 Oil: Total Production (Bbls) 304,507 228,068 204,983 Average sales price (per Bbl) $ 90.86 $ 64.76 $ 36.84 Natural Gas: Total Production (Mcf) 245,923 192,052 191,337 Average sales price (per Mcf) $ 6.41 $ 4.70 $ 1.72 NGL: Total Production (Bbls) 19,277 5,225 15,934 Average sales price (per Bbl) $ 40.87 $ 36.09 $ 11.20 Oil Equivalents: Total Production (Boe) (1) 364,771 265,302 252,807 Average Daily Production (Boe/d) 999 727 691 Average Production Costs (per Boe) (2) $ 13.12 $ 13.44 $ 13.09 _________________________ (1) Assumes 6 Mcf of natural gas equivalents to 1 barrel of oil. (2) Excludes workover costs, marketing, ad valorem and severance taxes. As of December 31, 2022, the Chaveroo and the Wattenberg fields and as of December 31, 2021, the Chaveroo, Milnesand and Wattenberg fields, and as of December 31, 2020, the Chaveroo and Milnesand fields 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, 2022, 2021, and 2020, are represented in the table below in total barrels (Bbls): 2022 2021 2020 Chaveroo (Permian Asset Base) 211,310 167,164 129,332 Milnesand (Permian Asset Base) - 8,840 7,868 Wattenberg (D-J Asset Base) 91,685 24,731 - The following table summarizes our gross and net developed and undeveloped leasehold and mineral fee acreage at December 31, 2022: Total Developed (1) Undeveloped (2) Gross Net Gross Net Gross Net D-J Basin 204,714 12,372 183,370 9,388 21,344 2,984 Permian Basin 33,456 31,308 30,693 29,916 2,763 1,392 Total 238,170 43,680 214,063 39,304 24,107 4,376 (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. 15 Table of Contents 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. Total Net Undeveloped Acreage Expiration In the event that production is not established or we take no action to extend or renew the terms of our leases, our net undeveloped acreage that will expire over the next three years as of December 31, 2022, is 66, 40, and 0 for the years ending December 31, 2023, 2024 and 2025, respectively 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, 2022. This summary includes crude oil wells in which we have a working interest: Gross Net Crude oil 112.0 66.1 Natural gas - - Total* 112.0 66.1 * Total percentage of gross operated wells is 53.6%. Drilling Activity We drilled wells or participated in the drilling of wells as indicated in the table below: 2022 2021 2020 Gross Net Gross Net Gross Net Development Productive 8 4.1 4 0.3 - - Dry - - - - - - Exploratory Productive - - - - - - Dry - - - - - - The following table sets forth information about wells for which drilling was in progress or which were drilled but uncompleted at December 31, 2022, which are not included in the above table: Drilling In Progress Drilled But Uncompleted Gross Net Gross Net Development wells - - 8 0.4 Exploratory wells - - - - Total - - 8 0.4 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, 2022, the Company’s total estimated proved reserves were 16.1 million Boe, of which 13.4 million Bbls were crude oil and NGL reserves, and 16.4 million Mcf were natural gas reserves. Internal Controls. Arvind Krishna Harikesavanallur, 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. 16 Table of Contents The preparation of our reserve estimates is in accordance with our prescribed procedures that include verification of input data into a reserve forecasting and economic software, as well as management review. Our reserve analysis includes, but is not limited to, the following: · Research of operators near our lease acreage. Review operating and technological techniques, as well as reserve projections of such wells. · 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) ”. Drilling and Completion and Leasing Activities For the year ended December 31, 2022, the Company incurred $23,131,000 of capital costs primarily related to drilling operations, completion and facility construction for the two new wells started at the end of 2021; approximately $8.4 million relating to production enhancement cleanouts in our Permian Basin Asset; and approximately $12.5 million for the acquisition and development of assets in the D-J Basin, which also includes our participation in the drilling and completion of six wells by a third-party operator in the latter part of the period. Additionally, the Company consummated the acquisition of certain additional assets located in the D-J Basin from a third-party effective July 1, 2021, for approximately $500,000 in cash consideration. These assets include approximately 46.6 net leasehold acres and interests in 14 horizontal wells currently producing from the acreage. The Company incurred $1.2 million (included in the $23.1 million total number above) in net capital costs for its working interest in these 14 new well interests during the year ended December 31, 2022. The Company also acquired approximately 480 net mineral acres and 787 net lease acres in and around its existing footprint in the D-J Basin through multiple transactions in 2022, at total acquisition and due diligence costs of $607,000 and $688,000, respectively. 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. We do not believe that we would be affected by any such action materially differently than similarly situated competitors. 17 Table of Contents At the state level, our operations in Colorado are regulated by the Colorado Oil & Gas Conservation Commission (“ COGCC ”) 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. The COGCC regulates oil and gas operators through rules, policies, written guidance, orders, permits, and inspections. Among other things, the COGCC enforces specifications regarding drilling, development, production, reclamation, enhanced recovery, safety, aesthetics, noise, waste, flowlines, and wildlife. In recent years, the COGCC has amended its existing regulatory requirements and adopted new requirements with increased frequency. For example, in January 2016, the COGCC approved new rules that require local government consultation and certain best management practices for large-scale oil and natural gas facilities in certain urban mitigation areas. These rules also require operator registration and/or notifications to local governments with respect to future oil and natural gas drilling and production facility locations. In February 2018, the COGCC comprehensively amended its regulations for oil, gas, and water flowlines to expand requirements addressing flowline registration and safety, integrity management, leak detection, and other matters. The COGCC has also adopted or amended numerous other rules in recent years, including rules relating to safety, flood protection, and spill reporting. In December 2018, the COGCC approved new rules that require new oil and gas sites to be situated at least 1,000 feet away from school properties such as playgrounds and athletic fields. Most recently, in 2019, Colorado enacted Senate Bill 19-181 (“ SB 19-181 ”), which changes the mission of the COGCC from fostering responsible and balanced development to regulating development to protect public health and the environment and directs the COGCC to undertake rulemaking on various operational matters including environmental protection, facility siting and wellbore integrity. Pursuant to this directive, in June 2020, the COGCC amended its regulations regarding wellbore integrity. The amended rules impose additional requirements regarding the permitting, construction, operation, and closure of wells. In addition, in further pursuance of this directive, on March 1, 2022 the COGCC adopted new financial assurance rules, effective April 30, 2022, that, among other things, ensure each operator has the financial capability to meet all of their obligations under SB 19-181, through the development of operator-specific financial assurance plans, increase financial assurance for transferred and inactive wells, require the creation of a financial assurance account for new wells funded in the initial years of operations, create an orphan well fund, provide for the application of Colorado’s new rules to federal wells, broaden access for local governments regarding plugging of wells, and develop an out-of-service plugging program. The new financial assurance rules became effective on April 30, 2022. We estimate that we will be required to pay approximately $100,000 annually in order to comply with these new financial assurance rules, which could increase in the event we drill additional wells. Further, the COGCC has recently imposed minimum requirements for ownership and consent in order to obtain a force pooling order. In addition, 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 COGCC submitted a notice of rulemaking on May 18, 2022, to implement SB 22-198 by amending the COGCC’s annual registration fee rules to now require that an operator’s annual registration fee be paid to the enterprise as a “mitigation fee.” In addition, the newly established “Enterprise Board” now has the authority to adjust the dollar amount of the mitigation fee. The 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 COGCC, 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. In New Mexico, the Company, through its New Mexico operating subsidiaries Ridgeway and EOR, has entered into Agreed Compliance Orders (“ ACOs ”) with the EMNRD with respect to the abandonment, restoration and remediation of its wells in its Permian Basin Asset. Ridgeway currently has an ACO in place with the EMNRD pertaining to approximately 284 legacy vertical wells operated by Ridgeway, and on November 10, 2022 EOR entered into an amended ACO (the “ Amended ACO ”) with the EMNRD pertaining to approximately 49 legacy vertical wells operated by EOR. Among other things, the Amended ACO provides that (i) no penalties were due from EOR, (ii) EOR would restore to production, or plug and abandon, the 49 wells listed in the Amended ACO by no later than December 31, 2024, (iii) EOR would provide monthly reports to the Director of the Oil Conservation Division (“ OCD ”) regarding actions taken for each well, (iv) EOR would maintain financial assurance for the wells and place $50,000 cash in an escrow account in New Mexico designating the OCD as beneficiary, which escrowed funds will be forfeit in the event EOR fails to meet any well plugging deadline, (v) EOR may request, and the OCD may grant, an extension of the deadlines under the Amended ACO for good cause shown, and (vi) EOR may not transfer a well to another operator unless approved by the OCD. The Company may be required to enter into new or amended ACOs with the EMNRD with respect to its Permian Basin Asset, which could require the accelerated restoration of production, or plugging and abandonment, of its legacy vertical wells in its Permian Basin Asset. 18 Table of Contents 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. 19 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. 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. 20 Table of Contents 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. Regulation of 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. Additionally, on January 14, 2019, in Martinez v. Colorado Oil and Gas Conservation Commission , the Colorado Supreme Court overturned a ruling by the Colorado Court of Appeals that held that the Colorado Oil & Gas Conservation Commission (“ COGCC ”) had held that the COGCC concluded that it lacked statutory authority to undertake a proposed rulemaking “to suspend the issuance of permits that allow hydraulic fracturing until it can be done without adversely impacting human health and safety and without impairing Colorado’s atmospheric resource and climate system, water, soil, wildlife, or other biological resources.” The Colorado Court of Appeals concluded that Colorado’s Oil and Gas Conservation Act mandated that oil and gas development “be regulated subject to the protection of public health, safety, and welfare, including protection of the environment and wildlife resources.” In the Colorado Supreme Court’s majority opinion, Justice Richard L. Gabriel wrote the COGCC is required first to “foster the development of oil and gas resources” and second “to prevent and mitigate significant environmental impacts to the extent necessary to protect public health, safety and welfare, but only after taking into consideration cost-effectiveness and technical feasibility.” 21 Table of Contents 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. 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 RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of oil or natural gas, if properly handled, are currently exempt from regulation as hazardous waste under RCRA and, instead, are regulated under RCRA’s less stringent non-hazardous waste provisions, state laws or other federal laws. However, it is possible that certain oil and natural gas drilling and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Stricter regulation of wastes generated during our operations could result in an increase in our, as well as the oil and natural gas exploration and production industry’s costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position. In December 2016, the U.S. District Court for the District of Columbia approved a consent decree between the EPA and a coalition of environmental groups. The consent decree requires the EPA to review and determine whether it will revise the RCRA regulations for exploration and production waste to treat such waste as hazardous waste. In April 2019, the EPA, pursuant to the consent decree, determined that revision of the regulations was not necessary. Information comprising the EPA’s review and decision is contained in a document entitled “Management of Exploration, Development and Production Wastes: Factors Informing a Decision on the Need for Regulatory Action”. The EPA indicated that it will continue to work with states and other organizations to identify areas for continued improvement and to address emerging issues to ensure that exploration, development and production wastes continue to be managed in a manner that is protective of human health and the environment. Environmental groups, however, expressed dissatisfaction with the EPA’s decision and will likely continue to press the issue at the federal and state levels. The Comprehensive Environmental Response, Compensation and Liability Act (“ CERCLA ”), also known as the Superfund law, and comparable state laws impose joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and former owners and operators of the site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We generate materials in the course of our operations that may be regulated as hazardous substances. We currently lease or operate numerous properties that have been used for oil and natural gas exploration, production and processing for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations, where such substances have been taken for treatment or disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or petroleum hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent future contamination, the costs of which could be substantial. 22 Table of Contents Water Discharges The federal Clean Water Act (“ CWA ”) and analogous state laws impose strict controls concerning the discharge of pollutants and fill material, including spills and leaks of crude oil and other substances. The CWA also requires approval and/or permits prior to construction, where construction will disturb certain wetlands or other waters of the U.S. (“ WOTUS ”). In 2019 and 2020, the EPA and the United States Army Corps of Engineers (“ USACE ”) issued a final rule to repeal previous regulations and promulgated a new replacement rule (the “ Navigable Waters Protection Rule ”). The Navigable Waters Protection Rule was vacated by two separate federal district courts in late 2021. On November 18, 2021, EPA and USACE issued a pre-publication version of another rule largely reinstating the previous 1986 WOTUS rule and guidance “with certain amendments” to reflect “consideration of the agencies’ statutory authority under the CWA and relevant Supreme Court decisions” (the “ 2021 Proposed Rule ”). The 2021 Proposed Rule was published in the Federal Register on December 7, 2021. In addition to the 2021 Proposed Rule, in September 2022, the EPA and USACE sent the draft final rule to implement the 2021 Proposed Rule to the Office of Management and Budget for interagency review, but no final rule has yet been issued by the agencies. It is unknown at this time when the 2021 Proposed Rule will take effect; when the next forthcoming proposed amendments are expected; and/or whether either new rule will be challenged and withstand any challenges in federal court. Finally, in January 2022, the United States Supreme Court granted review of Sackett vs. EPA , which involves issues related to CWA scope and jurisdiction and could impact the current rulemaking process. The Supreme Court heard oral arguments in Sackett in October 2022, and a decision is expected in 2023. Although the outcome of the 2021 Proposed Rule and additional forthcoming amendments to the WOTUS regulations is unknown, the regulations under the Biden Administration are undoubtedly more stringent in terms of the scope of WOTUS, which could ultimately change the scope of the CWA’s jurisdiction and result in increased costs and delays with respect to obtaining permits for discharges of pollutants or dredge and fill activities in waters of the U.S., including regulated wetland areas. As noted above, however, things are constantly in flux and the fate of the definition of “WOTUS” under the CWA and how that ultimately will be applied by the Agencies is yet to be seen. The CWA also regulates storm water run-off from crude oil and natural gas facilities and requires storm water discharge permits for certain activities. Spill Prevention, Control and Countermeasure (“ SPCC ”) requirements of the CWA require appropriate secondary containment, load out controls, piping controls, berms and other measures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon spill, rupture or leak. 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 Safe Drinking Water Act (“ 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. 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. 23 Table of Contents In June 2016, the EPA implemented new requirements focused on achieving additional methane and volatile organic compound reductions from the oil and natural gas industry. The rules imposed, among other things, new requirements for leak detection and repair, control requirements for oil well completions, replacement of certain pneumatic pumps and controllers and additional control requirements for gathering, boosting and compressor stations. On November 15, 2021, the EPA published a proposed rule that would update and expand existing requirements for the oil and gas industry, as well as creating significant new requirements and standards for new, modified, and existing oil and gas facilities. The proposed new requirements would include, for example, new standards and emission limitations applicable to storage vessels, well liquids unloading, pneumatic controllers, and flaring of natural gas at both new and existing facilities. In November 2022, the EPA published a supplemental proposal to update, strengthen, and expand the standards proposed in November 2021. The proposed rules for new and modified facilities are estimated to be finalized by the end of 2023, while any standards finalized for existing facilities will require further state rulemaking actions over the next several years before they become applicable and effective. In November 2022, the BLM published a proposed rule that would regulate venting, flaring and leaks during oil and gas production activities on federal and Indian leases. 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. In 2019, the EPA increased the state of Colorado’s non-attainment ozone classification for the Denver Metro North Front Range Ozone Eight-Hour Non-Attainment (“ Denver Metro/North Front Range NAA ”) area from “moderate” to “serious” under the 2008 national ambient air quality standard (“ NAAQS ”). This increase in non-attainment status to “serious” triggered significant additional obligations for the state under the CAA and resulted in Colorado adopting new and more stringent air quality control requirements in December 2020 that are applicable to our operations. Based on current air quality monitoring data, it is expected that the Denver Metro/North Front Range NAA will be further “bumped-up” to “severe” status. This will trigger additional obligations for the state under the CAA and will result in new and more stringent air quality permitting and control requirements, which may in turn result in significant costs and delays in obtaining necessary permits applicable to our operations. SB 19-181 also 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 COGCC 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 COGCC 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 COGCC, petitioning the COGCC 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. 24 Table of Contents 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. Regulation of GHG Emissions The EPA has published findings that emissions of carbon dioxide, methane and other greenhouse gases (“ 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 the past, Congress has considered proposed legislation to reduce emissions of GHGs. On August 16, 2022, the Inflation Reduction Act of 2022 (“ IRA ”) was signed into law. The IRA imposes a fee of up to $1,500 per metric ton of methane emitted above specified thresholds from onshore petroleum and natural gas production facilities, natural gas processing facilities, natural gas transmission and compression facilities, and onshore petroleum and natural gas gathering and boosting facilities, among other facilities. The fees will apply to methane emissions after January 1, 2024. 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 April 2021, President Biden announced that the United States would aim to cut its greenhouse gas emissions 50 percent to 52 percent below 2005 levels by 2030. This commitment will be part of the United States’ “nationally determined contribution,” or NDC, to the Paris Climate Agreement. The NDC will commit the United States to a voluntary GHG emission reduction target and outline domestic climate mitigation measures to achieve that target. Since 2014, Colorado has engaged in multiple rulemakings to adopt significant additional rules regulating methane emissions from the oil and gas sector, and Colorado is expected to continue these efforts over the next several years. Additionally, in response to Colorado General Assembly House Bill 19-1261, which established statewide greenhouse gas reduction targets in Colorado, on September 30, 2020, Colorado released a public comment draft of its Greenhouse Gas Pollution Reduction Roadmap, which details early action steps the state can take toward meeting the near-term goals of reducing greenhouse gas (“ GHG ”) pollution by 26% by 2025 and 50% by 2030 from 2005 levels. On October 23, 2020, the AQCC issued the Resolution to Ensure Greenhouse Gas Reduction Goals Are Met in support of the roadmap, which estimates emission reductions needed from the oil and gas sector of 36% by 2025 and 50% by 2030. To meet these targets, as well as to address other air quality and environmental justice issues, the AQCC held a hearing in December 2021 and voted to adopt additional requirements and emission limitations applicable to oil and gas facilities in Colorado. The adopted regulatory requirements include, for example, more frequent fugitive emissions monitoring, a statewide GHG intensity program, emission limitations for well liquids unloading, and comprehensive testing of emission control devices. Regulation of methane and other GHG emissions associated with oil and natural gas production could impose significant requirements and costs on our operations. Regulation of Flowlines In February 2018, the COGCC comprehensively amended its regulations for oil, gas and water flowlines in Colorado to expand requirements addressing flowline registration and safety, integrity management, leak detection and other matters. In November 2019, the COGCC further amended its flowline regulations pursuant to SB 19-181 to impose additional requirements regarding flowline mapping, operational status, certification and abandonment, among other things. The COGCC has also adopted or amended numerous other rules in recent years, including rules relating to safety, flood protection and spill reporting. 25 Table of Contents Hydraulic Fracturing Activities 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. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances. Additionally, the EPA published in June 2016 an effluent limitations guideline final rule pursuant to its authority under the SDWA prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants; asserted regulatory authority in 2014 under the SDWA over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities; and issued in 2014 a prepublication of its Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, the BLM published a final rule in March 2015 establishing new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands including well casing and wastewater storage requirements and an obligation for exploration and production operators to disclose what chemicals they are using in fracturing activities. However, following years of litigation, the BLM rescinded the rule in December 2017. Additionally, from time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In the event that a new, federal level of legal restrictions relating to the hydraulic fracturing process is adopted in areas where we operate, we may incur additional costs to comply with such federal requirements that may be significant in nature, and also could become subject to additional permitting requirements and experience added delays or curtailment in the pursuit of exploration, development, or production activities. 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. See further discussion in “ Part I ” - “ Item 1A. Risk Factors .” While there were no oil and gas ballot initiatives in 2022 that would have imposed additional regulations on the oil and gas industry in the State of Colorado, 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. 26 Table of Contents In addition, on September 28, 2020, the COGCC 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 new rule became effective January 1, 2021, and could likewise make it more difficult for us to undertake oil and gas development activities in Colorado. 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, legal restrictions imposed in that area 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 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. Activities on Federal Lands Oil and natural gas exploration, development and production activities on federal lands, including American Indian lands and lands administered by the BLM, are subject to the National Environmental Policy Act (“ NEPA ”). NEPA requires federal agencies, including the BLM, to evaluate major agency actions having the potential to significantly impact the environment. 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. We currently have limited exploration, development and production activities on federal lands, and our future exploration, development and production activities may include leasing and development of federal mineral interests, which will require the acquisition of governmental permits or authorizations that are subject to the requirements of NEPA. This process has the potential to delay or limit, or increase the cost of, the development of oil and natural gas projects. Authorizations under NEPA are also subject to protest, appeal or litigation, any or all of which may delay or halt projects. Moreover, depending on the mitigation strategies recommended in Environmental Assessments or Environmental Impact Statements, we could incur added costs, which may be substantial. On January 20, 2021, the Acting U.S. Interior Secretary, instituted a moratorium on new oil and gas leases and permits on federal onshore and offshore lands, which a federal court blocked with a preliminary injunction in June 2021, which injunction is being appealed. President Biden subsequently announced that his administration will resume onshore oil and gas lease sales on federal lands effective April 18, 2022. A total of approximately 26% of the Company’s acreage in New Mexico and 1% of the Company’s acreage in Colorado are 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. 27 Table of Contents 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. Other In October 2015, the U.S. Pipeline and Hazardous Materials Safety Administration (“ PHMSA ”), proposed to expand its regulations in a number of ways, including increased regulation of gathering lines, even in rural areas, and proposed additional standards to revise safety regulations applicable to onshore gas transmission and gathering pipelines in 2016. 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. Crude oil production is subject to many of the same operating hazards and environmental concerns as natural gas production, but is also subject to the risk of crude oil spills. In addition to Spill Prevention, Control, and Countermeasure Regulation (“ SPCC ”) requirements, the Oil Pollution Act of 1990 (“ OPA ”) establishes requirements for preparation and EPA approval of Facility Response Plans and subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages arising from crude oil spills. Noncompliance with OPA may result in varying civil and criminal penalties and liabilities. Historically, we have not experienced any significant crude oil discharge or crude oil spill problems. 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. Democratic control of the House, Senate and White House could lead to increased regulatory oversight and increased regulation and legislation, particularly around oil and gas development on federal lands, climate impacts and taxes. 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. 28 Table of Contents 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 .” Global Warming and Climate Change Various state governments and regional organizations have enacted, or are considering enacting, new legislation and promulgating new regulations governing or restricting the emission of GHG, including from facilities, vehicles and equipment. Legislative and regulatory proposals for restricting GHG emissions or otherwise addressing climate change could require us to incur additional operating costs and could adversely affect demand for the oil and natural gas that we sell or the cost of the equipment and other materials we use. The potential increase in our operating costs could include new or increased costs to obtain permits, operate and maintain our equipment, install new emission controls on our equipment, pay taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program. Additionally, the development of a federal renewable energy standard, or the development of additional or more stringent renewable energy standards at the state level could reduce the demand for the oil and gas we produce, thereby adversely impacting our earnings, cash flows and financial position. A cap-and-trade program generally would cap overall greenhouse gas emissions on an economy-wide basis and require major sources of greenhouse gas emissions or major fuel producers to acquire and surrender emission allowances. A federal cap and trade program or expanded use of cap and trade programs at the state level could impose direct costs on us through the purchase of allowances and could impose indirect costs by incentivizing consumers to shift away from fossil fuels. In addition, federal or state carbon taxes could directly increase our costs of operation and similarly incentivize consumers to shift away from fossil fuels. In addition, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in an increasing number of financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this may make it more difficult and expensive for us to secure funding. Members of the investment community have also begun to screen companies such as ours for sustainability performance, including practices related to greenhouse gases and climate change, before investing in our securities. Any efforts to improve our sustainability practices in response to these pressures may increase our costs, and we may be forced to implement technologies that are not economically viable in order to improve our sustainability performance and to meet the specific requirements to perform services for certain customers. These various legislative, regulatory and other activities addressing greenhouse gas emissions could adversely affect our business, including by imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations, which could require us to incur costs to reduce emissions of greenhouse gases associated with our operations. Limitations on greenhouse gas emissions could also adversely affect demand for oil and gas, which could lower the value of our reserves and have a material adverse effect on our profitability, financial condition and liquidity. Compliance with GHG laws or taxes could significantly increase our costs, reduce demand for fossil energy derived products, impact the cost and availability of capital and increase our exposure to litigation. Such laws and regulations could also increase demand for less carbon intensive energy sources. 29 Table of Contents 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. Human Capital Resources At December 31, 2022, 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/ped/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. 30 Table of Contents