What changed in this filing

/stocks — the workspaceLOADING

Item 1. Business

2024-03-07 compared with 2023-03-09 · 117 added, 172 removed, 280 unchanged (51% of the section changed)

Ring Energy, Inc., a Nevada corporation (“Ring,” “Ring Energy,” the “Company,” “we,” “us,” “our,” or similar terms), is a growth oriented independent exploration and production company based in The Woodlands, Texas and is engaged in oil and natural gas development, production, acquisition, and exploration activities currently focused in the Permian Basin of Texas.

Our primary drilling operations target the oil and liquids rich producing formations in the Northwest Shelf, the Central Basin Platform, and the Delaware Basin all of which are part of the Permian Basin in Texas.

Ring Energy, Inc., a Nevada corporation (“Ring,” “Ring Energy,” the “Company,” “we,” “us,” “our,” or similar terms), is a growth oriented independent oil and natural gas exploration and production company based in The Woodlands, Texas and is engaged in oil and natural gas development, production, acquisition, and exploration activities currently focused in the Permian Basin of Texas.

Our drilling operations target the oil and liquids rich producing formations in the Northwest Shelf and the Central Basin Platform, in the Permian Basin in Texas.

As of December 31, 2023, our leasehold acreage positions totaled 96,127 gross (80,535 net) acres and we held interests in 1,043 gross (864 net) producing wells.

Proved reserves as of December 31, 2022 were approximately 138.1 million Boe (barrel of oil equivalent), of which we are the operator of approximately 98%.

All of our properties are located in the Permian Basin.

Our proved reserves are oil-weighted with approximately 64% consisting of oil, 19% consisting of natural gas, and 17% consisting of natural gas liquids.

Of those reserves, approximately 65% are classified as proved developed or “PD” and 35% are classified as proved undeveloped, or “PUD.” Within the "PD" reserve category, 235 re-completion and re-activation opportunities are classified as proved developed not producing "PDNP" and within the "PUD" reserve category, we have a total of 214 proved locations (43% horizontal and 57% vertical) based on the reserve report as of December 31, 2022.We believe our core leasehold in the Northwest Shelf and Central Basin Platform contain additional potential drilling locations.

Proved reserves as of December 31, 2023 (based upon the report of our independent petroleum engineer of that date) were approximately 129.8 million Boe, of which we are the operator of approximately 98%.

All of our properties are located in the Permian Basin and our proved reserves are oil-weighted, with approximately 63% consisting of oil, 19% consisting of natural gas, and 18% consisting of NGLs.

Approximately 68% of the reserves are classified as PD and 32% are classified as PUD.

Within the PD reserve category, 242 recompletion and re-activation opportunities are classified as PDNP and within the PUD reserve category, we have a total of 211 proved locations (33% horizontal and 67% vertical) based on the reserve report as of December 31, 2023.

We believe our core leasehold in the Northwest Shelf and Central Basin Platform contain additional potential drilling locations.

For the calculation of Boe, a barrel of oil is weighted on a 6 to 1 ratio to one thousand cubic feet ("Mcf") of natural gas.

2023 Highlights and Major Developments

• Amended our revolving credit facility “RBL” with an initial borrowing base of $600.0 million

• Closed the Stronghold Acquisition on August 31, 2022

• Increased liquidity position at year-end 2022 to approximately $188.0 million which was a 205% increase versus year-end 2021 of $61.6 million

• Improved RBL available balance at year-end 2022 to $184.2 million or 31% of undrawn capacity on the RBL versus year-end 2021 of $59.2 million or 17% of undrawn capacity

• Closed the Founders Acquisition on August 15, 2023

• Achieved record full year production of 18,119 Boepd (69% oil), a year-over-year increase of 47%

• Executed a continuous drilling program in 2022 which included drilling 32.00 gross / 31.35 net operated wells consisting of 27.00 gross horizontal wells and 5.00 gross vertical wells

• Increased total Proved Reserves to 138.1 MMBoe at year-end 2022, a year-over-year increase of 78%

Ring’s mission is to deliver competitive and sustainable returns to its shareholders by developing, acquiring, exploring for, and commercializing oil and natural gas resources it believes are vital to the world’s health and welfare.

• Executed a phased drilling program in 2023 that included drilling 31.00 gross / 29.75 net operated wells consisting of 20.00 horizontal and 11.00 vertical wells (gross).

In addition, the Company participated in 5.00 non-operated wells.

• Maintained our revolving credit facility borrowing base of $600 million

• Total Proved Reserves were 129.8 MMBoe at year-end 2023

Ring’s mission is to deliver competitive and sustainable returns to its shareholders by developing, acquiring, exploring for, and commercializing oil and natural gas resources that are vital to the world’s health and welfare.

Our Key Principles

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• ensure health, safety, and environmental excellence, and a strong commitment to Ring’s employees and the communities in which we work and operate;

• continue our focus on generating free cash flow to improve and build a sustainable financial foundation;

• continue our focus on generating adjusted free cash flow to improve and build a sustainable financial foundation;

• pursue rigorous capital discipline focused on Ring’s highest returning opportunities;

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This objective is key to profitably growing our production and reserve levels and generating the excess cash from operations.

Focus on generating free cash flow and strengthen our balance sheet - We seek to continuously reduce long-term debt using excess cash from operations and potentially through the sale of non-core assets.

Continuing to generate free cash flow through a disciplined capital allocation program and reducing our operating and corporate costs are key components of this objective.

Our capital program is funded by operational cash flow and limited to balance our production and reserve growth versus paying down debt.

Focus on generating adjusted free cash flow and strengthening our balance sheet - We seek to continuously reduce long-term debt using excess cash from operations and potentially through the sale of non-core assets.

Continuing to generate adjusted free cash flow through a disciplined capital allocation program and reducing our operating and corporate costs are key components of this objective.

Our capital program is funded by operational cash flow and seeks to balance our production and reserve growth with paying down debt.

We believe that remaining focused and disciplined in this regard will lead to meaningful returns for our shareholders and provide additional financial flexibility to manage potential future swings in business cycles.

Our commodity hedges are designed to help ensure the necessary cash flow to adhere to these plans while retaining the flexibility to participate in prevailing commodity markets.

Pursue strategic acquisitions that maintain or reduce our break-even costs - We actively pursue accretive acquisitions, mergers and dispositions in seeking to improve our margins, returns, and break-even costs.

Financial strategies associated with these efforts will focus on delivering competitive debt-adjusted per share returns.

Pursue strategic acquisitions that maintain or reduce our break-even costs - We actively pursue accretive acquisitions, mergers, and property dispositions in seeking to improve our margins, returns, and break-even costs.

Financial strategies associated with these efforts focus on delivering competitive debt-adjusted per share returns.

This objective is key to delivering competitive returns to our shareholders on a sustainable basis.

Stronghold Acquisition

On July 1, 2022, Ring and Stronghold Energy II Operating, LLC, a Delaware limited liability company (“Stronghold OpCo”) and Stronghold Energy II Royalties, LP, a Delaware limited partnership (“Stronghold RoyaltyCo”, together with Stronghold OpCo, collectively, “Stronghold”), entered into a purchase and sale agreement (the “Purchase Agreement"), under which Ring acquired (the “Stronghold Acquisition”) interests in oil and gas leases and related property of Stronghold consisting of approximately 37,000 net acres in the Central Basin Platform of the Texas Permian Basin.

On August 31, 2022, we completed the Stronghold Acquisition.

Upon closing of the Stronghold Acquisition, Stronghold exercised its right to designate two directors to our Board of Directors (the "Board").

On September 1, 2022, Roy I.

Ben-Dor and David S.

Habachy were appointed to the Board.

Founders Acquisition

On August 15, 2023, the Company, as buyer, and Founders Oil & Gas IV, LLC (“Founders”), as seller, closed the Asset Purchase Agreement (the “Founders Purchase Agreement”) under which the Company acquired (the “Founders Acquisition”) interests in oil and gas leases and related property of Founders in the Central Basin Platform of the Permian Basin in Ector County, Texas.

Common Warrants Exercised

During 2023, the Company reduced its dilutive shares through the exercise of 19,029,593 of the Company's outstanding common warrants, bringing the total outstanding to 78,200 common warrants as of December 31, 2023.

This was accomplished by the exercise of 4,517,427 common warrants at an exercise price of $0.80 per share and the exercise of 14,512,166 common warrants at an exercise price of $0.62 per share, through amendments to certain warrant agreements.

These exercises resulted in $12,301,596 of net proceeds to the Company after payment of $309,888 in advisory fees.

Primary Business Operations

We seek to rigorously manage our asset portfolio to optimize shareholder value over the long term.

In the first quarter of 2022, we contracted a rig for our horizontal drilling program and began operations on January 31st.

We drilled and completed three 1-mile horizontal wells and one 1.5-mile horizontal well in the Central Basin Platform.

We then moved the rig to the Northwest Shelf and drilled two 1-mile horizontal wells.

All wells drilled in the first quarter had a working interest of 100%.

In the second quarter of 2022, we drilled a total of nine wells, completed seven wells, and began the completion process on four wells, all in the Northwest Shelf.

The first wells completed were the two 1-mile horizontal wells, which were drilled in the first quarter.

Next, we drilled and completed two 1-mile horizontal wells with a working interest of 100%, two 1.5-mile horizontal wells with a working interest of approximately 98.7% and one 1-mile horizontal well with a working interest of approximately 75.4%.

We also drilled and began the completion process on an additional four 1-mile horizontal wells.

Two of the wells have a working interest of 100%, one has a working interest of approximately 87.9%, and the fourth has a working interest of 75%.

In the third quarter of 2022, we completed and placed on production the four aforementioned 1-mile horizontal wells in the Northwest Shelf, which were drilled in the second quarter.

Next, we drilled and completed two 1.5-mile horizontal wells and one 1-mile horizontal well in the Central Basin Platform and two 1-mile horizontal wells in the Northwest Shelf, each with a working interest of 100%.

During the last month of the quarter, we drilled and began the completion process on three 1-mile horizontal wells in the Northwest Shelf, two with a working interest of 99.7% and one with a working interest of 100%.

In total, during the third quarter of 2022, we drilled eight, completed nine, and began the completion process on three horizontal wells.

With the addition of the Stronghold Acquisition assets in the Central Basin Platform, we also performed three vertical well re-completions.

In the fourth quarter of 2022, we completed and placed on production the three aforementioned 1-mile horizontal wells in the Northwest Shelf.

Next, we drilled and completed two 1-mile horizontal wells with a working interest of 100%, also in the Northwest Shelf.

To complete the 2022 horizontal drilling program, we drilled and completed two 1.5-mile horizontal wells in the Central Basin Platform.

In addition to the horizontal wells, we performed nine more vertical well re-completions and drilled and completed five new vertical wells on the Stronghold Acquisition assets located in Crane County, Texas, of the Central Basin Platform, all with a working interest of 100%.

In summary, for 2022, we drilled and completed 27 horizontal wells and 5 vertical wells, along with 12 vertical well re-completions on the Stronghold Acquisition assets.

The table below sets forth our drilling and completion activities for 2022 by quarter through December 31, 2022.

In the first quarter of 2023, in the Northwest Shelf, the Company drilled and completed two 1-mile horizontal wells (each with a working interest of 100%), and two 1.5-mile horizontal wells (one with a working interest of approximately 99.8% and the other with a working interest of approximately 75.4%).

Next, in its Crane County acreage within the Central Basin Platform, the Company drilled and completed three vertical wells (each with a working interest of 100%) and performed six vertical well recompletions (each with a working interest of 100%).

In the second quarter of 2023, in the Northwest Shelf, the Company drilled and completed two 1.5-mile horizontal wells (one with a working interest of 100% and the other with a working interest of approximately 75.4%) and two 1-mile horizontal wells (both with a working interest of approximately 91.1%).

Additionally, in its Crane County acreage within the Central Basin Platform, the Company drilled and completed two vertical wells (each with a working interest of 100%) and performed three vertical well recompletions (each with a working interest of 100%).

During the third quarter of 2023, the Company drilled and completed two 1-mile horizontal wells (one with a working interest of 100% and the other with a working interest of 75%) in the Northwest Shelf, and three 1.5-mile horizontal wells (each with a working interest of 100%) in the Central Basin Platform.

Additionally, in its Crane County acreage within the Central Basin Platform, the Company drilled and completed three vertical wells (each with a working interest of 100%).

Lastly, the Company drilled and began the completion process on three 1-mile horizontal wells in the Northwest Shelf (each with a working interest of 100%).

In the fourth quarter of 2023, the Company completed and placed on production the three aforementioned 1-mile horizontal wells in the Northwest Shelf.

Additionally, the Company drilled and completed one saltwater disposal (SWD) well in the Northwest Shelf (with a working interest of 100%), and completed the 2023 horizontal drilling program with one 1.5-mile horizontal well in the Northwest Shelf (with a working interest of approximately 97.7%), as well as two 1-mile horizontal wells and one 1.5-mile horizontal well (each with a working interest of 100%) in the Central Basin Platform.

In its Crane County acreage within the Central Basin Platform, the Company drilled and completed three vertical wells (each with a working interest of 100%).

In summary, for 2023, the Company drilled and completed 20 horizontal wells, 11 vertical wells, and 1 SWD well.

In addition, the Company performed 9 vertical well recompletions.

The table below sets forth our drilling and completion activities for 2023 by quarter, and full year total through December 31, 2023.

Quarter Area Wells Drilled Wells Completed Recompletions

1Q 2022 Central Basin Platform (Horizontal) 4 4 —

1Q 2023 Northwest Shelf (Horizontal) 4 4 —

Central Basin Platform (Horizontal) — — —

Central Basin Platform (Vertical) 3 3 6

Northwest Shelf 2 — —

2Q 2022 Central Basin Platform (Horizontal) — — —

2Q 2023 Northwest Shelf (Horizontal) 4 4 —

Central Basin Platform (Horizontal) — — —

Central Basin Platform (Vertical) 2 2 3

Northwest Shelf 9 7 —

3Q 2022 Central Basin Platform (Horizontal) 3 3 —

3Q 2023 Northwest Shelf (Horizontal) 5 2 —

Central Basin Platform (Horizontal) 3 3 —

Central Basin Platform (Vertical) 3 3 —

Northwest Shelf 5 6 —

4Q 2022 Central Basin Platform (Horizontal) 2 2 —

4Q 2023 Northwest Shelf (Horizontal) 1 4 —

Central Basin Platform (Horizontal) 3 3 —

Central Basin Platform (Vertical) 3 3 —

Northwest Shelf 2 5 —

Northwest Shelf (Horizontal) 14 14 —

Central Basin Platform (Horizontal) 6 6 —

Central Basin Platform (Vertical) 11 11 9

(1) Fourth quarter total and full year total do not include one SWD well completed in the Northwest Shelf.

Ring Energy’s Strengths

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These factors can be particularly important in the areas in which we operate.

In addition, those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects, and to evaluate, bid for, and purchase a greater number of properties and prospects than what our financial or technical resources permit.

In addition, those companies may be able to pay more for productive oil and natural gas properties

and exploratory prospects, and to evaluate, bid for, and purchase a greater number of properties and prospects than what our financial or technical resources permit.

Our ability to acquire additional properties and to find and develop reserves in the future will depend on our ability to identify, evaluate, and select suitable properties and to consummate transactions in this highly competitive environment.

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This commitment is tied to existing natural gas purchase contracts associated with our production, which potentially gives such gathering companies certain short-term relative monopolistic powers to set gathering and transportation costs.

Obtaining the services of an alternative gathering company would require substantial additional costs (since an alternative gathering company would be required to lay new pipeline and/or obtain new rights of way to any lease from which we are selling production).

Obtaining the services of an alternative gathering company is not currently realistic as it would require substantial additional costs (since an alternative gathering company would be required to lay new pipeline and/or obtain new rights of way to any lease from which we are selling production).

We are not subject to third-party gathering systems with respect to our oil production.

Some of our oil production is sold through a third-party pipeline which has no regional competition and all other oil production is transported by the oil purchaser by trucks with competitive trucking costs in the area.

Some of our oil production is sold through third-party pipelines which have no regional competition and all other oil production is transported by the oil purchaser by trucks with competitive trucking costs in the area.

Our oil is transported from the wellhead to tank batteries or delivery points through our flow-lines or gathering systems.

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We have implemented a Leak Detection and Repair program, or LDAR, to locate and repair leaking components including valves, pumps and connectors, in order to minimize the emission of fugitive volatile organic compounds and hazardous air pollutants.

In addition, we install vapor recovery units in our newly installed tank batteries which also reduces emissions.

Our produced salt water is generally moved by pipeline connected to our operated salt water disposal wells or by pipeline to commercial disposal facilities.

In addition, as an ongoing practice, we install vapor recovery units in our newly installed tank batteries which also reduces emissions.

Our produced saltwater is generally moved by pipeline connected to our operated saltwater disposal wells or by pipeline to commercial disposal facilities.

Major Customers

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In areas where there is no practical access to pipelines, oil is trucked to storage facilities.

For the year ended December 31, 2022, sales to three customers, Phillips 66 Company ("Phillips"), NGL Crude Partners ("NGL Crude"), and Enterprise Crude Oil LLC ("Enterprise") represented 68%, 13% and 5%, respectively, of our oil, natural gas, and natural gas liquids revenues.

As of December 31, 2022, Phillips represented 69% of our accounts receivable, NGL Crude represented 7% of our accounts receivable and Enterprise represented 10% of our accounts receivable.

We believe that the loss of any of these customers would not materially impact our business because we could readily find other purchasers for our oil and natural gas.

For the year ended December 31, 2023, sales to three customers, Phillips 66 Company ("Phillips"), Enterprise Crude Oil LLC ("Enterprise"), and NGL Crude Partners ("NGL Crude"), and represented 66%, 12%, and 10%, respectively, of our oil, natural gas, and natural gas liquids revenues.

As of December 31, 2023, Phillips represented 65% of our accounts receivable, Enterprise represented 11% of our accounts receivable and NGL Crude represented 8% of our accounts receivable.

We believe that the loss of any of these purchasers would not materially impact our business because we could readily find other purchasers for our oil and natural gas.

Delivery Commitments

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Commodity Hedging

We have an active commodity hedging program through which we seek to hedge a meaningful portion of our expected oil and gas production, reducing our exposure to downside commodity prices and enabling us to protect cash flows to meet our debt obligations under our credit facility and maintain liquidity to fund our capital expenditures needs.

We have an active commodity hedging program through which we seek to hedge a meaningful portion of our expected oil and gas production, thereby reducing our exposure to downside commodity prices and enabling us to protect cash flows to meet our debt obligations under our credit facility and secondarily to maintain liquidity to fund our capital expenditures needs.

Governmental Regulations

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This ruling has caused federal agencies to delay issuing new oil and gas leases and permits on federal lands and waters.

While we do not have a significant federal lands acreage position (240 net acres as of December 31, 2022), these actions could have a material adverse effect on our industry and the Company.

Currently, all of our properties and operations are in Texas and New Mexico, which have regulations governing conservation matters, such as the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells.

Currently, all of our operated properties are in Texas, which has regulations governing conservation matters, such as the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells.

The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing.

Moreover, both Texas and New Mexico impose a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within their jurisdictions.

Moreover, Texas imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdictions.

The failure to comply with these rules and regulations can result in substantial penalties.

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Regulation of Transportation of Oil

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices, however, Congress could reenact price controls in the future.

Sales of crude oil, condensate, and NGLs are not currently regulated and are made at negotiated prices;

however, Congress could reenact price controls in the future.

Our sales of crude oil are affected by the availability, terms, and cost of transportation.

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Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions.

The basis for intrastate oil pipeline regulation, and the

degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state.

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

Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors.

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Regulation of Transportation and Sale of Natural Gas

Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938 (“NGA”), the Natural Gas Policy Act of 1978 (“NGPA”) and regulations issued under those Acts by the FERC.

under those Acts by the FERC.

In the past, the federal government has regulated the prices at which natural gas could be sold.

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As described below, there are various regulations issued by the EPA and other governmental agencies pursuant to these federal statutes that govern our operations.

In Texas and New Mexico, specific oil and natural gas regulations apply to oil and natural gas operations, including the drilling, completion and operations of wells, and the disposal of waste oil and saltwater.

In Texas, specific oil and natural gas regulations apply to oil and natural gas operations, including the drilling, completion and operations of wells, and the disposal of waste oil and saltwater.

There are also procedures incident to the plugging and abandonment of dry holes or other non-operational wells, all as governed by the applicable governing state agency.

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These potentially responsible parties include (1) the current owners and operators of a facility, (2) the past owners and operators of a facility at the time the disposal or release of a hazardous substance occurred, (3) parties that arranged for the offsite disposal or treatment of a hazardous substance, and (4) transporters of hazardous substances to off-site disposal or treatment facilities.

While petroleum and natural gas liquids are not designated as a “hazardous substance” under CERCLA, other chemicals used in or generated by our operations may be regulated as hazardous substances.

Potentially responsible parties under CERCLA may be subject to strict, joint and several liability for the costs of investigating and cleaning up environmental contamination, for damages to natural resources and for the costs of certain health studies.

While petroleum and NGLs are not designated as a “hazardous substance” under CERCLA, other chemicals used in or generated by our operations may be regulated as hazardous substances.

responsible parties under CERCLA may be subject to strict, joint and several liability for the costs of investigating and cleaning up environmental contamination, for damages to natural resources and for the costs of certain health studies.

In addition to statutory liability under CERCLA, common law claims for personal injury or property damage can also be brought by neighboring landowners and other third parties related to contaminated sites.

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These permits may require us to install emission control technologies to limit emissions, which can impose significant costs on our business.

In 2012 and 2016, the EPA issued New Source Performance Standards to regulate emissions of sources of volatile organic compounds (“VOCs”), sulfur dioxide, air toxics and methane from various oil and natural gas exploration, production, processing and transportation facilities.

On May 12, 2016, the EPA amended its regulations to impose new standards for methane and volatile organic compounds emissions for certain new, modified, and reconstructed equipment, processes, and activities across the oil and natural gas sector.

In September 2020, the EPA finalized amendments to the 2016 standards that removed the transmission and storage segment from the oil and natural gas source category and rescinded the methane-specific requirements for production and processing facilities.

However, President Biden signed an executive order on his first day in office calling for the suspension, revision, or rescission of the September 2020 rule and the reinstatement or issuance of methane emission standards for new, modified, and existing oil and gas facilities.

Given the long-term trend toward increasing regulation, future federal Greenhouse Gas (“GHG”) regulations of the oil and gas industry remain a

possibility, and several states have separately imposed their own regulations on methane emissions from oil and gas production activities.

In November 2021, the EPA proposed new source performance standards and emissions guidelines to reduce methane and other pollution from new and existing sources in the oil and gas industry.

The proposed rule would include, among other things, a comprehensive monitoring program for new and existing well sites, zero-emissions standards for new and existing pneumatic controls, and standards to eliminate venting of associated gas and requirements for the capture and sale of natural gas where a sales line is available.

If adopted, these requirements could increase our costs to operate and control pollution.

In November 2022, the EPA issued a Supplemental Proposal regarding the proposed new source performance standards and emissions guidelines for reducing methane and VOCs in the oil and natural gas sector.

The Supplemental Proposal expands the November 2021 proposal to include more comprehensive requirements to reduce emissions, including application of methane monitoring obligations to wellhead-only sites and well sites with low emissions.

It also would create a new third-party monitoring program to flag large emissions events known as the “Super-Emitter Response Program.” The EPA expects to finalize its new methane rules in 2023.

The foregoing laws, regulations, and standards, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or mandate the use of specific equipment or technologies to control emissions.

Until these rules are formally adopted, we cannot predict the final regulatory requirements or the cost to comply with such requirements with any certainty.

In November 2021, the EPA issued a proposed rule under the CAA’s New Source Performance Standards, known as Subpart OOOOa, intended to reduce methane emissions from new and existing oil and gas sources.

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

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

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

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

Notably, the 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 deadlines under state plans.

The final rule gives states two years to develop and submit their plans for reducing methane emissions from existing sources.

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

Compliance with these or any new regulations could result in stricter permitting requirements, which in turn could delay or impair our ability to obtain air emission permits and could result in increased expenditures for pollution control equipment, the costs of which could be significant.

On August 16, 2022, President Biden signed the Inflation Reduction Act of 2022 (“IRA”).

The IRA allocated $1.55 billion to the Methane Emissions and Waste Reduction Incentive Program.

The IRA also required the EPA to implement a waste emission charge on methane emitted from applicable oil and gas facilities that exceed certain thresholds.

The IRA also required the EPA to

implement a waste emission charge on methane emitted from applicable oil and gas facilities that exceed certain thresholds.

The methane charge goes into effect in 2024 at $900 per metric ton of methane and increases to $1,500 per metric ton of methane by 2026.

The charge will act as an incentive for operators to reduce emissions by minimizing leaks and replacing equipment rather than paying for excessive emissions.

In November 2022, the Department of the Interior announced a proposed rule from the Bureau of Land Management (“BLM”) that would impose additional requirements on oil and natural gas production on federal and Tribal lands, including the use of “low bleed” pneumatic equipment and vapor recovery for oil storage tanks, implementation of leak detection plans, implementation of waste minimization plans, and monthly limits on royalty-free flaring.

If adopted, these rules could affect our adversely affect our production of oil and gas pursuant to federal leases in New Mexico.

In October 2015, the EPA announced that it was lowering the primary National Ambient Air Quality Standards (“NAAQS”) for ozone from 75 parts per billion to 70 parts per billion.

Since that time, the EPA has issued area designations with respect to ground-level ozone.

In December 2020, the EPA announced its intention to leave the ozone NAAQS unchanged at 70 parts per billion rather than lower them further.

However, as discussed above, that action could be subject to reversal following the Biden Administration’s January 2021 executive order.

In mid-2022, the Biden Administration announced that it was considering designating the Permian Basin in Texas as a “non-attainment zone,” which, if designated, would result in increased permitting and compliance requirements for drilling operations in the state to decrease ozone levels.

The Biden Administration has since omitted the potential designation from an agenda of planned regulations, indicating that it is not expected to be finalized in the next year.

The EPA, however, could revive the effort in the future.

In 2022, the New Mexico Environment Department (“NMED”) adopted “ozone precursor rules.” The ozone precursor rules went into effect on August 5, 2022 and apply to oil and gas sources in New Mexico that would cause or contribute to ambient ozone concentrations that exceed 95% of the NAAQs for ozone.

As of the effective date, these rules apply to oil and natural gas production in the following counties in New Mexico:

Chaves, Dona Ana, Eddy, Lea, Rio Arriba, Sandoval, San Juan, and Valencia.

The rules apply to certain crude oil and natural gas production and processing equipment associated with operations.

Reclassification of areas of state implementation of NAAQS, or designation of areas in which we operate as non-attainment zones, could result in stricter permitting requirements, delay, or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant.

Moreover, the NMOCD recently adopted new rules, which require oil and gas operators to capture 98 percent of their methane waste by the end of 2026.

The new rules went into effect on May 25, 2021.

On January 12, 2024, the EPA announced a proposed rule to implement the methane emissions charge.The charge will act as an incentive for operators to reduce emissions by minimizing leaks and replacing equipment rather than paying for excessive emissions.

While the State of Texas has not formally conducted a recent rulemaking related to air emissions, scrutiny of oil and natural gas operations and the rules affecting them have increased in recent years.

For example, the EPA and environmental non-governmental organizations have conducted flyovers with optical gas imaging cameras to survey emissions from oil and natural gas production facilities and transmission infrastructure.

In August 2022, for example, the EPA announced that it would be conducting helicopter flyovers of the Permian Basin region in New Mexico and Texas.

The flyovers used infrared cameras to survey oil and gas operations to identify large emitters of methane and VOCs.

In August 2022, for example, the EPA announced that it would be conducting helicopter flyovers of the Permian Basin region in Texas.

The flyovers used infrared cameras to survey oil and gas operations to identify large emitters of methane and volatile organic compounds ("VOCs").

Based on data obtained during flyovers, EPA intends to initiate enforcement follow up actions with facilities operators.

In addition, the RRC has increased oversight

related to flaring, with reporting reviews and site inspections.

In addition, the RRC has increased oversight related to flaring, with reporting reviews and site inspections.

While none of these activities increases our compliance obligations, they signal the potential for increased enforcement and possible rulemaking in the future.

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In January 2023, the EPA and the Corps issued a final rule that revises the definition of WOTUS.

The final rule has been challenged by several states and industry groups.

As a result of these developments, the scope of federal jurisdiction under the CWA is uncertain at this time.

The pending litigation and future regulations concerning the definition of WOTUS may result in an expansion of the scope of the CWA’s jurisdiction, and we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in WOTUS in connection with our operations.

Separately, in May 2023, the U.S.

Supreme Court’s decision in Sackett v.

EPA narrowed federal jurisdiction over wetlands to “traditional navigable waters” and wetlands or other waters that have a “continuous surface connection” with or are otherwise indistinguishable from traditional navigable water.

In September 2023, the EPA and the Corps published a direct-to-final rule that conforms the regulatory definition of “Waters of the United States” to the Supreme Court’s May 2023 decision in Sackett.

However, litigation opposing the September 2023 final rule remains ongoing and substantial uncertainty exists with respect to future implementation of the September 2023 rule and the scope of CWA jurisdiction more generally.

To the extent the rule or any future rule or court decision expands the scope of the CWA’s jurisdiction, we could face increased permitting costs and project delays.

Underground Injection Control

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Under the auspices of the federal UIC program as implemented by states with UIC primacy, regulators, particularly at the state level, are becoming increasingly sensitive to possible correlations between underground injection and seismic activity.

Consequently, state regulators implementing both the federal UIC program and state corollaries are

heavily scrutinizing the location of injection facilities relative to faulting and are limiting both the density and injection facilities as well as the rate of injection.

In New Mexico, the New Mexico Oil Conservation Division (“NMOCD”) administers the UIC program for all injection wells that are related to oil and natural gas production.

In Texas, the Texas Railroad Commission (“RRC”) regulates the disposal of produced water by injection well.

Permits must be obtained before drilling saltwater disposal wells, and casing integrity monitoring must be conducted periodically to ensure the casing is not leaking salt water to groundwater.

Consequently, state regulators implementing both the federal UIC program and state corollaries are heavily scrutinizing the location of injection facilities relative to faulting and are limiting both the density and injection facilities as well as the rate of injection.

In Texas, the RRC regulates the disposal of produced water by injection well.

Permits must be obtained before drilling saltwater disposal wells, and casing integrity monitoring must be conducted periodically to ensure the casing is not leaking saltwater to groundwater.

Contamination of groundwater by oil and natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs, among other sanctions and liabilities under the SDWA and state laws.

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Among other things, the rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells and allow the RRC to modify, suspend, or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity.

In 2021, the NMOCD announced a new plan for responding to increased seismic activity in the Permian Basin.

Under the new plan, pending permits for wastewater injection in certain areas will be subject to additional reporting and monitoring requirements.

More stringent regulation of injection wells could lead to reduced construction or the capacity of such wells, which could in turn impact the availability of injection wells for disposal of wastewater from our operations.

Increased costs associated with the transportation and disposal of produced water, including the cost of complying with regulations concerning produced water disposal, may reduce our profitability.

The costs associated with the disposal of proposed water are commonly incurred by all oil and natural gas producers, however, and we do not believe that these costs will have a material adverse effect on our operations.

The costs associated with the disposal of produced water are commonly incurred by all oil and natural gas producers, however, and we do not believe that these costs will have a material adverse effect on our operations.

In addition, third-party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury.

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For example, the EPA published permitting guidance in February 2014 addressing the use of diesel fuel in fracturing operations, and in June 2016 EPA issued final effluent limitations guidelines under the CWA that waste-water from shale natural gas extraction operations must meet before discharging to a publicly owned treatment works.

Separately, the BLM published a final rule in March 2015 that establishes new or more stringent standards for performing hydraulic fracturing on federal and Indian lands.

However, a Wyoming federal court struck down this rule in June 2016.

The June 2016 decision was appealed by the BLM to the U.S.

Circuit Court of Appeals for the Tenth Circuit.

However, following issuance of a presidential executive order to review rules related to the energy industry, in July 2017, the BLM published a notice of proposed rulemaking to rescind the 2015 final rule.

In September 2017, the Tenth Circuit issued a ruling to vacate the Wyoming trial court decision and dismiss the lawsuit challenging the 2015 rule in light of the BLM’s proposed rulemaking.

The BLM issued a final rule repealing the 2015 hydraulic fracturing rule in December 2017.

The current administration has announced that it intends to review the repeal of the 2015 hydraulic fracturing rule under the Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis .

Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process but, at this time, federal legislation related to hydraulic fracturing appears uncertain.

In Texas and New Mexico, specific oil and natural gas regulations apply to oil and gas operations, including the drilling, completion and operations of wells, and the disposal of waste oil and salt water.

In Texas, specific oil and natural gas regulations apply to oil and gas operations, including the drilling, completion and operations of wells, and the disposal of waste oil and salt water.

In October 2023, the RRC announced draft amendments to its water protection rules to, among other things, encourage waste recycling.

There are also procedures incident to the plugging and abandonment of dry holes or other non-operational wells, all as governed by the applicable governing state agency.

As an example, the RRC adopted rules in 2014 requiring companies seeking permits for disposal wells to provide seismic activity data in permit applications.

The rules also allow the RRC to modify, suspend, or terminate permits if a disposal well is determined to be causing seismic activity.

The rules also allow the RRC to modify,

suspend, or terminate permits if a disposal well is determined to be causing seismic activity.

Determinations by the RRC under these rules may adversely affect our operations.

In New Mexico, the Produced Water Act, effective July 1, 2019, governs the discharge, handling, transport, storage, and recycling or treatment of produced water.

Additionally, New Mexico has adopted regulations that require the disclosure of information regarding the substances used in the hydraulic fracturing process.

In January 2021, State Senator Antoinette Sedillo Lopez of New Mexico, introduced a bill which would prohibit certain uses of fresh water in fracking operations, require the disclosure of the chemical composition of produced water from spills, and increase penalties for produced water spills by the oil and gas industry.

State Senator Sedillo introduced another bill for the 2021 legislative session seeking to prevent the New Mexico Energy, Minerals and Natural Resources Department from issuing new fracking permits until 2025.

Similar legislation was unsuccessful in the 2019 and 2020 legislative sessions.

However, if enacted, this legislation would have a material adverse effect on our business and prospects.

Local governments may also seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular.

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Continuing political and social attention to the issue of global climate change has resulted in both existing and pending international agreements and national, regional or local legislation and regulatory measures to limit or reduce emissions of so-called greenhouse gases (“GHGs”), such as cap and trade regimes, carbon taxes, restrictive permitting, increased fuel efficiency standards and incentives or mandates for renewable energy.

In December 2009, the EPA published an endangerment finding concluding that emissions of CO 2 , methane and certain other GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes.

Based on its findings, the EPA has adopted and implemented regulations under existing provisions of the CAA that, among other things, establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit requirements for GHG emissions from certain large stationary sources that already are major sources of criteria pollutants under the CAA.

The EPA has adopted and implemented regulations under existing provisions of the CAA that, among other things, establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit requirements for GHG emissions from certain large stationary sources that already are major sources of criteria pollutants under the CAA.

Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that typically are GHG emissions could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities that exceed GHG emission thresholds.

In addition, the EPA has adopted rules requiring the reporting of GHG emissions from oil and natural gas production and processing facilities on an annual basis, as well as reporting GHG emissions from gathering and boosting systems, oil well completions and workovers using hydraulic fracturing.

In June 2016, the EPA finalized rules to reduce methane emissions from new, modified or reconstructed sources in the oil and natural gas sector, including implementation of a leak detection and repair (“LDAR”) program to minimize methane emissions, under the CAA’s New Source Performance Standards in 40 C.F.R.

Part 60, Subpart OOOOa (“GHG NSPS”).

On April 18, 2017, the EPA announced its intention to reconsider certain aspects of those regulations, and in June 2017, the EPA proposed a two-year stay of certain requirements of the GHG NSPS regulations.

In October 2018, the EPA proposed revisions to the GHG NSPS, such as changes to the frequency for monitoring fugitive emissions at well sites and changes to requirements that a professional engineer certify when meeting certain GHG NSPS requirements is technically infeasible.

EPA proposed further revisions to the GHG NSPS on September 24, 2019, including rescinding the methane requirements in the GHG NSPS that apply to sources in the production and processing segments of the industry.

In September 2020, the EPA finalized amendments to the GHG NSPS that rescind requirements for the transmission and storage segment of the oil and natural gas industry and rescind methane-specific limits that apply to the industry’s production and processing segments, among other things.

The current administration has announced that it intends to review the September 2020 rules under the Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis , which review may result in the reinstatement of the now-rescinded standards or promulgation of more stringent standards.

Our Company has taken measures to control methane leaks, but it is possible that these rules and future revisions thereto will require us to take further methane emission reduction measures, which may require us to expend material sums.

In addition, in November 2016, the BLM issued final rules to reduce methane emissions from venting, flaring, and leaks during oil and natural gas operations on federal lands that are substantially similar to the GHG NSPS requirements.

However, in December 2017, the BLM published a final rule to temporarily suspend or delay certain requirements contained in the November 2016 final rule until January 17, 2019, including those requirements relating to venting, flaring and leakage from oil and gas production activities.

Further, in September 2018, the BLM published a final rule revising or rescinding certain provisions of the 2016 rule, which became effective on November 27, 2018.

Both the 2016 and the 2018 rule were challenged in federal court.

On July 21, 2020, a Wyoming federal court vacated almost all of the 2016 rule, including all provisions relating to the loss of gas through venting, flaring, and leaks, and on July 15, 2020, a California federal court vacated the 2018 rule.

As a result of these decisions, the 1979 regulations concerning venting, flaring and lost production on federal land have been reinstated.

The current administration is likely to impose new regulations on GHG emissions from oil and natural gas production operations on federal land, given the long-term trend towards increasing regulation in this area.

Part 60, Subpart OOOOa (“GHG NSPS”) requirements.

In September 2018, the BLM published a final rule revising or rescinding certain provisions of the 2016 rule, which became effective on November 27, 2018.

Both the 2016 and the 2018 rule were challenged in federal court resulting in the rescission of both rules.

Appeals to those decisions are ongoing, but with little activity in the last several years.

Moreover, several states have already adopted rules requiring operators of both new and existing sources to develop and implement an LDAR program and to install devices on certain equipment to capture methane emissions.

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In November 2022, the United States participated in the United Nations Climate Change Conference in Egypt (“COP27”).

Further, several states, including New Mexico, and local governments remain committed to the principles of the Paris Agreement in their effectuation of policy and regulations.

Although it is not possible at this time to predict what additional domestic legislation may be adopted in light of the Paris Agreement or the Glasgow Climate Pact, or how legislation or new regulations that may be adopted based on the Paris Agreement or the Glasgow Climate Pact to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, limiting emissions of GHGs from, our equipment and operations, or restricting federal leases could impair our production, could require us to incur costs to reduce emissions of GHGs associated with our operations and could decrease demand for oil and natural gas.

In December 2023, the United States participated in the United Nations Climate Change Conference in the United Arab Emirates (“COP28”).

Further, several states and local governments remain committed to the principles of the Paris Agreement in their effectuation of policy and regulations.

Although it is not possible at this time to predict what additional domestic legislation may be adopted in light of the Paris Agreement or the

Glasgow Climate Pact, or how legislation or new regulations that may be adopted based on the Paris Agreement or the Glasgow Climate Pact to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, limiting emissions of GHGs from, our equipment and operations, or restricting federal leases could impair our production, could require us to incur costs to reduce emissions of GHGs associated with our operations and could decrease demand for oil and natural gas.

In September 2023, the Biden Administration directed federal agencies to consider the Social Cost of GHGs metric in budgeting, procurement and other agency decisions, including in environmental reviews, where appropriate.

Several states, though none in the areas where we operate, have implemented, of their own accord or in coordination with their neighbor states, regional initiatives and programs limiting, monitoring or otherwise regulating GHG emissions.

The adoption and implementation of any laws or regulations imposing reporting obligations on, or limiting emissions of GHG from, our equipment and operations could require additional expenditures to reduce emissions of GHGs associated with its operations or could adversely affect demand for the oil and natural gas we produce, and thus possibly have a material adverse effect on our revenues, as well as having the potential effect of lowering the value of our reserves.

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We will monitor and comply with any such promulgated rules.

Threatened and endangered species, migratory birds and natural resources

Threatened and endangered species

Various federal and state statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds, wetlands, and natural resources.

These statutes include the Endangered Species Act (“ESA”), the Migratory Bird Treaty Act (“MBTA”) and the Clean Water Act.

Fish and Wildlife Service (“FWS”) may designate critical habitat areas that it believes are necessary for survival of threatened or endangered species.

As a result of a 2011 settlement agreement, the FWS was required to determine whether to identify more than 250 species as endangered or threatened under the ESA by no later than completion of the agency’s 2017 fiscal year.

The FWS missed the deadline but reportedly continues to review new species for protected status under the ESA pursuant to the settlement agreement.

A critical habitat designation could result in further material restrictions on federal land use or on private land use and could delay or prohibit land access or development.

Where takings of or harm to species or damages to wetlands, habitat, or natural resources occur or may occur, government entities or at times private parties may act to prevent or restrict oil and natural gas exploration activities or seek damages for any injury, whether resulting from drilling or construction or releases of oil, wastes, hazardous substances or other regulated materials, and in some cases, criminal penalties may result.

Similar protections are offered to migratory birds under the MBTA.

Recently, there have been renewed calls to review protections currently in place for the dunes sagebrush lizard, whose habitat includes portions of the Permian Basin, and to reconsider listing the species under the ESA.

While some of our operations may be located in areas that are designated as habitats for endangered or threatened species or that may attract migratory birds, we believe that we are in substantial compliance with the ESA and the MBTA, and we are not aware of any proposed ESA listings that will materially affect our operations.

Nevertheless, we are monitoring listings and proposed listings by the FWS to ensure continued compliance.

In November 2022, FWS listed the southern distinct population segments of the lesser prairie-chicken that occupy habitats in eastern New Mexico and the southwest Texas Panhandle.

In January 2023, FWS listed the Sacramento Mountains checkerspot butterfly in New Mexico.

The federal government in the past has issued indictments under the MBTA to several oil and natural gas companies after dead migratory birds were found near reserve pits associated with drilling activities.

In January 2020, a new DOI rule went into effect clarifying that only the intentional taking of protected migratory birds is subject to prosecution under the MBTA.

In December 2021, however, that rule was revoked, and a new rule took effect reinstating the prohibition on incidental takes under the MBTA.

The identification or designation of 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 or could result in limitations on our development activities that could have an adverse impact on our ability to develop and produce our oil and natural gas reserves.

Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat.

Fish and Wildlife Service (“FWS”) may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species.

A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development.

The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause increased costs arising from species protection measures or could result in limitations on development activities that could have an adverse impact on the ability to develop and produce reserves within our assets.

If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.

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Our staff’s diversity is reflected in our full-time employees where 23% are women and approximately 50% represent minorities.

The majority of our employees are citizens of the United States, with a few retaining dual citizenships in other countries.

The majority of our employees are citizens of the United States, with a few retaining dual citizenship in other countries.

The employees who are not US citizens, are legally registered to live and work here and the Company is committed to helping those employees retain their ability to remain in the US and continue their employment.

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

What changed 10-K

Item 1. Business