What changed in this filing

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Item 1. Business

2024-03-18 compared with 2023-03-29 · 267 added, 212 removed, 399 unchanged (55% of the section changed)

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Dairy Ashford, Suite 210, Houston, Texas 77079.

We lease that space pursuant to a lease that expires in August 2023.

We lease that space pursuant to a lease that expires in February 2027.

Business Operations

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

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

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.

As of December 31, 2023, we held approximately 22,721 net Permian Basin acres located in Chaves and Roosevelt Counties, New Mexico, through our wholly-owned subsidiary, Pacific Energy Development Corp.

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

(“ RAZO ”), which asset we refer to as our “ Permian Basin Asset .” Also as of December 31, 2023, we held approximately 19,214 net D-J Basin acres located in Weld and Morgan Counties, Colorado, and Laramie County, Wyoming, through our wholly-owned subsidiary, PRH Holdings LLC (“ PRH ”), and which are operated by our wholly-owned operating subsidiary, Red Hawk Petroleum, LLC (“ Red Hawk ”), which asset we refer to as our “ D-J Basin Asset .” As of December 31, 2023, we held interests in 300 gross and net wells in our Permian Basin Asset, of which 25 are active producers, two are active injectors and two are active salt water disposal wells (“ SWD’ s”), all of which are held by PEDCO and operated by RAZO, and interests in 98 gross (24.6 net) wells in our D-J Basin Asset held by PRH, all of which 18 gross (16.2 net) wells are operated by Red Hawk and currently producing, 63 gross (8.4 net) wells are non-operated, and 17 wells have an after-payout interest.

Business Strategy

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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.

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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.

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

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.

Our net capital expenditures for 2024 are estimated at the time of this Annual Report to range between $20 million to $30 million.

This estimate includes a range of $17 million to $27 million for drilling and completion costs on our Permian Basin and D-J Basin Assets and approximately $3 million in estimated capital expenditures for ESP purchases, rod pump conversions, recompletions, well cleanouts, leasing, facilities, remediation and other miscellaneous capital expenses.

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

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

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

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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 2024 development program is based upon our current outlook for the year and is subject to revision, if and as necessary, to react to market conditions, product pricing, contractor availability, requisite permitting, capital availability, partner non-consents, capital allocation changes between assets, acquisitions, divestitures and other adjustments determined by the Company in the best interest of its shareholders while prioritizing our financial strength and liquidity.

We expect that we will have sufficient cash available to meet our needs over the next 12 months after the filing of this report and in the foreseeable future, including to fund our 2024 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.

Kukes, our Chief Executive Officer and director, which funding Dr.

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

In addition, we may seek additional funding through asset sales, farm-out arrangements, and credit facilities to fund potential acquisitions during the remainder of 2024.

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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.

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.

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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.

In addition, 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.

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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.

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

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

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

We generally sell a significant portion of our oil and gas production to a relatively small number of customers, and during the year ended December 31, 2022, sales to two customers comprised 63% and 20%, respectively, of the Company’s total oil and gas revenues.

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, 2023, sales to three customers comprised 42%, 35% and 18%, respectively, of the Company’s total oil and gas revenues.

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

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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 estimated net capital expenditures for 2023 are estimated at the time of this Annual Report to range between $25 million to $35 million.

Our net capital expenditures for 2024 are estimated at the time of this Annual Report to range between $20 million to $30 million.

This estimate includes a range of $17 million to $20 million for drilling and completion costs on our Permian Basin and D-J Basin Asset and approximately $3 million in estimated capital expenditures for ESP purchases, rod pump conversions, recompletions, well cleanouts, leasing, facilities, remediation and other miscellaneous capital expenses.

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

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

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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.

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

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

In the first acquisition, we acquired 100% of the assets of Hunter Oil Company, with an effective date of September 1, 2018, which created our core Permian position.

In 2019, we acquired additional assets in two bolt-on acquisitions from private operators.

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.

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

Our current Permian Basin Asset interests are all located in Chaves and Roosevelt Counties, New Mexico, where we currently operate 300 gross and net wells, of which 25 wells are active producers, two wells are active injectors, and two are active SWDs.

As of December 31, 2023, 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.

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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:

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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.

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

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

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

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

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

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

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

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

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

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

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

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

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

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.

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

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

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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.

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

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

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

PRH has an interest in 98 gross (24.6 net) wells and our wholly-owned operating subsidiary, Red Hawk, 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.

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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.

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

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

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

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

Weld and Morgan Counties, Colorado and Laramie County, Wyoming

Production, Sales Price and Production Costs

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

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.

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

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

The applicable production volumes from these fields for the years ended December 31, 2023, 2022, and 2021, are represented in the table below in total barrels (Bbls):

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Total Net Undeveloped Acreage Expiration

In the event that production is not established or we take no action to extend or renew the terms of our leases, our net undeveloped acreage that will expire over the next three years as of December 31, 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.

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

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.

The following table presents our ownership in productive crude oil and natural gas wells at December 31, 2023.

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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.

Arvind Krishna, our Director of Development and Reservoir Engineering (a non-executive position), is the technical person primarily responsible for our internal reserves estimation process (which is based upon the best available production, engineering and geologic data) and has in excess of five years as a reserves estimator and provides oversight of the annual audit of our year end reserves by our independent third party engineers.

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

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

Current Year Events

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

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

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

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

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

Drilling and Completion and Leasing Activities

For the year ended December 31, 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;

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

These costs were primarily related to:

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

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

and approximately $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.

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

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

Regulation of the Oil and Gas Industry

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

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

At the state level, our operations in Colorado are regulated by the 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).

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

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

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.

Regulation Affecting Production

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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

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.

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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.”

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.

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.

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

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

Federal Air Regulation

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.

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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.

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

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

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

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

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

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

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

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

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

18-1203, in which the D.C.

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

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

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

Circuit, and the D.C.

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

of County Comm.

of Weld County v.

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

In November 2022, the BLM published a proposed rule that would regulate venting, flaring and leaks during oil and gas production activities on federal and Indian leases.

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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.

State Air Regulation

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

The AQCC has undertaken a multi-year rulemaking process to implement the requirements of SB 19-181, including a rulemaking to require continuous emission monitoring equipment at oil and gas facilities.

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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.

In 2020, the ECMC relied in part on a previously-performed human health risk assessment in adopting new siting requirements.

The new requirements prohibit the siting of locations within 2,000 feet of a school facility or child-care center.

A similar 2,000-foot setback requirement applies to residential and high occupancy building units, but there are “off ramps” allowing oil and gas operators to site their drill pads as close as 500 feet from building units in certain circumstances.

The 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 ECMC also generally prohibited the venting or flaring of natural gas during drilling, completion, and production operations.

In addition, on August 30, 2022, environmental groups filed a petition for rulemaking with the ECMC, petitioning the ECMC to adopt new rules to evaluate and address the cumulative air impacts of oil and gas development in Colorado.

The petition proposes to address the cumulative air impacts of oil and gas development by effectively prohibiting any oil and gas project located in an area where the air quality exceeds, or may exceed, applicable air quality standards.

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

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

AQCC is expected to undertake several rulemaking efforts to further reduce emissions in the next several years.

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

The final rule is expected to take effect in 2024.

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

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

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.

Hydraulic Fracturing Activities

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

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

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

Hydraulic Fracturing

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

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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.

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

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

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

Federal agencies have periodically considered additional regulation of hydraulic fracturing.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

A final rule is expected in April 2024.

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

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

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

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

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

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 16% of the Company’s acreage in New Mexico, 1% of the Company’s acreage in Colorado, and 3% of the Company’s acreage in Wyoming is located on federal lands.

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

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

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

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

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

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

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

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

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

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

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

Other State Laws

At the state level, Colorado, where we conduct significant operations, is among the states that has adopted, and other states are considering adopting, regulations that could impose new or more stringent permitting, disclosure or well-construction requirements on hydraulic fracturing operations.

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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.

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

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

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

In addition, on September 28, 2020, the COGCC 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.

In addition, on September 28, 2020, the COGCC (now the ECMC) voted in favor of a preliminary approval establishing a new 2,000-foot setback rule from buildings for drilling and fracturing operations statewide, increasing the previous 500-foot setback rule, which 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.

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

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

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

We anticipate that the ECMC, the Conservation Division of the New Mexico Energy, Minerals, Natural Resources Department, the New Mexico State Land Office, the New Mexico Environment Department and other federal, state and local authorities will continue to adopt new rules and regulations moving forward which will likely affect our oil and gas operations and could make it more costly for our operations or limit our activities.

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

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

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

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

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

Moreover, because most of our operations are conducted in two particular areas, the Permian Basin in New Mexico and the D-J Basin in Colorado, 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.

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

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

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

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.

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.

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.

Water Discharges

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

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

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

Army Corps of Engineers (the “ USACE ").

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Although defenses exist, they are limited.

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

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

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

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

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

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