What changed in this filing

/stocks — the workspaceLOADING

Item 1. Business

2023-03-29 compared with 2022-03-11 · 92 added, 99 removed, 519 unchanged (27% of the section changed)

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Optimization of well density and configuration.

We own properties that are legacy conventional oil fields characterized by widespread vertical development and geological well control.

We utilize the extensive petrophysical and production data of such legacy properties to confirm optimal well spacing and configuration using modern reservoir evaluation methodologies.

We own properties that are legacy oil fields characterized by widespread vertical and horizontal development and geological well control.

We utilize the extensive geological, petrophysical and production data of such legacy properties to confirm optimal well spacing and configuration using modern reservoir evaluation methodologies.

Maintain a high degree of operational control.

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

We intend to utilize our strategic partners and funding which we expect to be available through the sale of debt or equity, to continuously fund development and operations.

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.

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

This estimate includes a range of $33 million to $38 million for drilling and completion costs on our Permian Basin and D-J Basin Assets and approximately $2 million in estimated capital expenditures for ESP purchases, rod pump conversions, recompletions, well cleanouts, leasing, facilities, and other miscellaneous capital expenses.

This estimate includes a range of $23 million to $33 million for drilling and completion costs on our Permian Basin and D-J Basin Assets and approximately $2 million in estimated capital expenditures for ESP purchases, rod pump conversions, recompletions, well cleanouts, leasing, facilities, remediation and other miscellaneous capital expenses.

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

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

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

Risk Factors “).

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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 2022 development program incorporates an increase in both basins relating to service cost inflation resulting in an estimated cost increase of approximately 10 to 15 percent per well, based on costs we have experienced since the third quarter of 2021.

Our 2022 development program is based upon our current outlook for the remainder of the year and is subject to revision, if and as necessary, to react to market conditions, product pricing, contractor availability, requisite permitting and capital availability, 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 foreseeable future, including to fund the remainder of our 2022 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 SK Energy LLC (“ SK Energy ”), which is 100% owned and controlled by Simon Kukes, our Chief Executive Officer and director, which funding SK Energy is under no obligation to provide, (iv) public or private debt or equity financings, including up to $3.6 million in securities which we may sell in the future in an on-going “at the market offering”, of which no shares have been sold in connection with to date, and (v) funding through credit or loan facilities.

Our 2023 development program incorporates service costs that have remained relatively flat, based on costs we have experienced since the third quarter of 2022.

Our 2023 development program is based upon our current outlook for the year and is subject to revision, if and as necessary, to react to market conditions, product pricing, contractor availability, requisite permitting, capital availability, partner non-consents, capital allocation changes between assets, acquisitions, divestitures and other adjustments determined by the Company in the best interest of its shareholders while prioritizing our financial strength and liquidity.

We expect that we will have sufficient cash available to meet our needs over the next 12 months after the filing of this report and in the foreseeable future, including to fund our 2023 development program, discussed above, which cash we anticipate being available from (i) projected cash flow from our operations, (ii) existing cash on hand, (iii) equity infusions or loans (which may be convertible) made available from Dr.

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

Kukes is under no obligation to provide, (iv) public or private debt or equity financings, including up to $3.5 million in securities which we may sell in the future in an on-going “at the market offering”, subject to availability under the Company’s shelf-registration, which limits the maximum amount of securities which can be sold in any 12 month period to 1/3 of the Company’s then public float, and (v) funding through credit or loan facilities.

In addition, we may seek additional funding through asset sales, farm-out arrangements, and credit facilities to fund potential acquisitions during the remainder of 2023.

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*Represents percentage of total voting power based on 87,040,267 shares of common stock outstanding as of March 29, 2023, with beneficial ownership calculated in accordance with Rule 13d-3 of the Exchange Act.

Holdings of SK Energy LLC are also included in holdings of Senior Management and the Board – See “ Part III ” — “ Item 12.

Holdings of The SGK 2018 Revocable Trust are also included in holdings of Senior Management and the Board - See “ Part III ” - “ Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters .

Impact of COVID-19

In December 2019, a novel strain of coronavirus, which causes the infectious disease known as COVID-19, was reported in Wuhan, China.

The World Health Organization declared COVID-19 a “ Public Health Emergency of International Concern ” on January 30, 2020, and a global pandemic on March 11, 2020.

COVID-19 and the governmental responses thereto significantly reduced worldwide economic activity during much of 2020, and continues to threaten the global economy, as variants and mutations of the disease continue to spread, even as vaccines and boosters have become more widely available.

While oil and gas prices have increased above pre-pandemic levels, it is not possible at this time for the Company to estimate the full impact that COVID-19 will have on the Company’s business in the future as such estimate would need to be based on whether or not COVID-19 continues to spread and the effectiveness of the containment of the virus, by the governments of countries affected and in which the Company operates.

However, the Company’s operations have previously been disrupted, and may be disrupted again in the future due to COVID-19.

The COVID-19 outbreak and mitigation measures have also had an adverse impact on global economic conditions, as well as an adverse effect on the Company’s business and financial condition and may continue to have an adverse effect on the Company, including on its potential to conduct financings on terms acceptable to the Company, if at all.

The Company implemented temporary precautionary measures intended to help minimize the risk of the virus to its employees, vendors, and guests, including limiting the number of occupants at the Company’s Houston headquarters and requiring all others to work remotely, and discouraged employee attendance at in-person work-related meetings, which could negatively affect the Company’s business, which measures have recently eased in accordance with federal, state and local guidance, and the vaccination of substantially all of the Company’s office-based employees.

The extent to which the COVID-19 outbreak will continue to impact the Company’s results will depend on future developments that are highly uncertain and cannot be predicted, including new information that may emerge concerning the severity of the virus, the continued availability and efficacy of vaccines and booster shots, the willingness of individuals to be vaccinated initially, and to obtain booster shots, the effect of virus mutations, and the actions to contain its impact.

Any future decrease in the price of oil, or the demand for oil and gas, as a result of COVID-19 or otherwise, will likely have a negative impact on our results of operations and cash flows.

In response to the effects of COVID-19, the Company has adopted policies, procedures, and practices both in its Houston office headquarters and across its field operations to protect its employees, contractors, and guests from COVID-19, including the adoption of a COVID-19 Response Plan, implementation of contractor questionnaires to assess COVID-19 risk and exposure prior to entering any Company facility or worksite, adopting best practices, guidelines and protocols recommended by the Centers for Disease Control (the “ CDC ”) and the Office of the Texas Governor for the prevention of exposure and spread of COVID-19, and instituting twice-monthly management calls discussing the COVID-19 pandemic and the Company’s ongoing response to the COVID-19 pandemic and effectiveness thereof.

Given the Company’s robust online systems and workflow practices and procedures, the Company has not experienced any material challenges or reductions in efficiency or effectiveness of its office-based workforce, while its field personnel continue to attend to their daily field operations uninterrupted, while mindful of social distancing and other preventative measures and safeguards recommended by the CDC, and subject to the CDC’s updated guidance.

We plan to continue to closely monitor the global energy markets and oil and gas pricing, with the remainder of our 2022 development plan being subject to revision, if and as necessary, to react to market conditions in the best interest of its shareholders, while prioritizing its financial strength and liquidity.

The oil and natural gas industry is highly competitive.

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We have assembled a management team at our Company with extensive experience in the fields of business development, petroleum engineering, geology, field development and production, operations, planning and corporate finance.

Our management team is headed by our Chief Executive Officer, Simon Kukes, who was formerly the CEO at Samara-Nafta, a Russian oil company partnering with Hess Corporation, President and CEO of Tyumen Oil Company, and Chairman of Yukos Oil.

Our management team is headed by our Chief Executive Officer, Dr.

Simon Kukes, who was formerly the CEO at Samara-Nafta, a joint venture with the U.S.-based international oil company Hess Corporation, CEO of Tyumen Oil Company (TNK), prior to its combination with British Petroleum, and Chairman of Yukos Oil Company.

Our President, J.

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

Moore, has over 15 years of energy industry experience, and formerly served as acting general counsel of Erin Energy Corp.

Moore, has nearly 20 years of energy industry experience, and formerly served as acting general counsel of Erin Energy Corp.

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

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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 90 potential net wells, comprised of 49 net 1.0-mile lateral wells, 40 net 2.0-mile lateral wells, and 1 net 1.5-mile lateral well, on 80-acre spacing, 160-acre spacing, and 120-acre spacing, respectively, providing us with a substantial drilling inventory for future years.

We believe our D-J Basin Asset could contain up to 204 potential gross wells with 79 potential net wells, comprised of 52 gross 1.0-mile lateral wells with 20 net 1.0-mile lateral wells, 12 gross 1.5-mile lateral wells with 6 net 1.5 mile lateral wells, 140 gross 2.0-mile lateral wells with 53 net 2.0 mile lateral wells, on 80-acre spacing, 120-acre spacing, and 160-acre spacing, respectively, providing us with a substantial drilling inventory for future years.

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

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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 in the D-J Basin.

Our strategy is to be the operator and/or a significant working interest owner, directly or through our subsidiaries and joint ventures, in the majority of our Permian Basin acreage so we can dictate the pace of development in order to execute our business plan.

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

This estimate includes a range of $33 million to $38 million for drilling and completion costs on our Permian Basin and D-J Basin Asset and approximately $2 million in estimated capital expenditures for ESP purchases, rod pump conversions, recompletions, well cleanouts, leasing, facilities, and other miscellaneous capital expenses.

This estimate includes a range of $23 million to $33 million for drilling and completion costs on our Permian Basin and D-J Basin Asset and approximately $2 million in estimated capital expenditures for ESP purchases, rod pump conversions, recompletions, well cleanouts, leasing, facilities, remediation and other miscellaneous capital expenses.

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

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

Risk Factors ”).

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The D-J Basin’s Wattenberg Extension has seen a tremendous amount of growth in drilling activity since 2018 due to enhanced completions design and interest in the area as a result of its remote location away from more populated areas of the Wattenberg play to the south.

The area did experience a slow down during early 2020 due to the COVID-19 pandemic and related oil market crash but activity has more recently come back to pre-pandemic levels with the recovery of oil prices.

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.

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

As of December 31, 2021, the Chaveroo and Milnesand fields in our Permian Basin Asset and Wattenberg field in our D-J Basin Asset and as of December 31, 2020 and December 31, 2019, the Chaveroo and Milnesand fields, are the fields that each comprise 15% or more of our total proved reserves.

As of December 31, 2022, the Chaveroo and the Wattenberg fields and as of December 31, 2021, the Chaveroo, Milnesand and Wattenberg fields, and as of December 31, 2020, the Chaveroo and Milnesand fields are the fields that each comprise 15% or more of our total proved reserves.

The applicable production volumes from these fields for the years ended December 31, 2022, 2021, and 2020, are represented in the table below in total barrels (Bbls):

Chaveroo (Permian Asset Base)

Milnesand (Permian Asset Base)

Wattenberg (D-J Asset Base)

The following table summarizes our gross and net developed and undeveloped leasehold and mineral fee acreage at December 31, 2022:

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Total Net Undeveloped Acreage Expiration

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, 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.

The following table presents our ownership in productive crude oil and natural gas wells at December 31, 2022.

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Internal Controls.

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

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

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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) ”.

2021 Material Events

Common Stock Offerings

On February 5, 2021, the Company closed an underwritten public offering of 5,968,500 shares of common stock at a public offering price of $1.50 per share, which included the full exercise of the underwriter’s over-allotment option, for net proceeds (after deducting the underwriters’ discount equal to 6% of the public offering price and expenses associated with the offering) of approximately $8.2 million.

On October 6, 2021, the Company closed a registered direct offering of 4,458,600 shares of common stock at a price of $1.57 per share for net proceeds (after deducting the placement agent’s fees and other estimated offering expenses associated with the offering) of approximately $6.5 million.

PPP Loan Forgiveness

On June 2, 2020, the Company received loan proceeds of $370,000 under the U.S.

Small Business Administration’s Paycheck Protection Program established as part of the Coronavirus Aid, Relief and Economic Security Act described in further detail in “Part II” - “ Item 8.

Financial Statements and Supplementary Data” – “Note 7 – PPP Loan ”.

Effective May 20, 2021, the Company received notification that the SBA had fully forgiven the $370,000 Paycheck Protection Program loan principal ($370,000) and accrued interest of $4,000.

Drilling and Completion Activities

In latter part of 2021, drilling operations began on two additional San Andres horizontal wells in the Permian Basin.

Completion operations for these wells is taking place in Q1 2022.

Four non-operated working interest wells in the D-J Basin were also participated in during the latter part of 2021, from which we also accrued production in the latter part of 2021.

In February 2022, the Company consummated the acquisition of certain additional DJ Basin assets from a third party, effective July 1, 2021, for approximately $500,000 in cash consideration.

Drilling and Completion and Leasing Activities

For the year ended December 31, 2022, the Company incurred $23,131,000 of capital costs primarily related to drilling operations, completion and facility construction for the two new wells started at the end of 2021;

approximately $8.4 million relating to production enhancement cleanouts in our Permian Basin Asset;

and approximately $12.5 million for the acquisition and development of assets in the D-J Basin, which also includes our participation in the drilling and completion of six wells by a third-party operator in the latter part of the period.

Additionally, the Company consummated the acquisition of certain additional assets located in the D-J Basin from a third-party effective July 1, 2021, for approximately $500,000 in cash consideration.

These assets include approximately 46.6 net leasehold acres and interests in 14 horizontal wells currently producing from the acreage.

The estimated total drilling and completion expense payable by the Company for its working interest in these 14 new well interests is approximately $2.4 million

The Company incurred $1.2 million (included in the $23.1 million total number above) in net capital costs for its working interest in these 14 new well interests during the year ended December 31, 2022.

The Company also acquired approximately 480 net mineral acres and 787 net lease acres in and around its existing footprint in the D-J Basin through multiple transactions in 2022, at total acquisition and due diligence costs of $607,000 and $688,000, respectively.

Regulation of the Oil and Gas Industry

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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, increases financial assurance for transferred and inactive wells, requires financial assurance account for new wells funded in the initial years of operations, creates an orphan well fund, applies Colorado’s new rules to federal wells, broadens access for local governments regarding plugging of wells, and develops an out-of-service plugging program.

The new rules will increase the bonding requirements, and related expense, related to our current and future oil and gas wells in Colorado.

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 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 is not necessary.

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:

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The 2021 Proposed Rule was published in the Federal Register on December 7, 2021.

In addition to the 2021 Proposed Rule, EPA and USACE plan to develop yet another amendment to the WOTUS regulations, which is expected to build upon the regulatory foundation in the 2021 Proposed Rule with the benefit of additional stakeholder engagement and public input.

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;

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EPA , which involves issues related to CWA scope and jurisdiction and could impact the current rulemaking process.

Although the outcome of the 2021 Proposed Rule and additional forthcoming amendments to the WOTUS regulations is unknown, the regulations under the Biden Administration have already shown to be 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.

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 related governmental agencies is yet to be seen.

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.

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

In September 2018, the EPA proposed revisions to the 2016 rules.

The proposed amendments address certain technical issues raised in administrative petitions and include proposed changes to, among other things, the frequency of monitoring for fugitive emissions at well sites and compressor stations.

In September 2020, the EPA issued a new rule which amended the 2016 requirements.

In this rule, the EPA removed all sources in the transmission and storage segment of the oil and natural gas industry from regulation.

The rule also rescinded the methane requirements in the 2016 regulations and loosened monitoring and repair regulations aimed at preventing methane leaks.

On June 30, 2021, however, President Biden signed into law a joint Congressional resolution disapproving and invalidating much of the 2020 rule amendments under the prior Presidential Administration, including the 2020 rule’s rescission of the methane requirements.

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

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

The proposed rules for new and modified facilities are expected to be finalized by the end of 2022, while any standards finalized for existing facilities will require further state rulemaking actions over the next several years before they become applicable and effective.

In November 2016, the BLM finalized rules to further regulate venting, flaring and leaks during oil and natural gas production activities on onshore federal and Indian leases (the “ 2016 Rule ”).

The 2016 Rule required additional controls and impose new emissions and other standards on certain operations on applicable leases, including committed state or private tracts in a federally approved unit or communitized agreement that drains federal minerals.

In September 2018, the BLM published a final rule that revised the 2016 Rule (the “ 2018 Revised Rule ”).

The 2018 Revised Rule, among other things, rescinded the 2016 Rule requirements related to waste-minimization plans, gas-capture percentages, well drilling, well completion and related operations, pneumatic controllers, pneumatic diaphragm pumps, storage vessels and leak detection and repair.

The 2018 Revised Rule also revised provisions related to venting and flaring.

Environmental groups and the States of California and New Mexico filed challenges to the 2018 rule in the United States District Court for the Northern District of California, and in July 2020, the United States District Court for the Northern District of California vacated the BLM’s 2018 Revised Rule.

However, in October 2020, the United States District Court for the District of Wyoming issued a ruling vacating the 2016 Rule, holding that the BLM exceeded its statutory authorities and acted arbitrarily.

Both rulings have been appealed.

The Spring 2021 Unified Agenda of Regulatory and Deregulatory Actions, published by the Office of Management and Budget’s Office of Information and Regulatory Affairs, identified a potential proposal by the BLM to update its existing rules governing the venting and flaring of natural gas (methane) from onshore Federal and Indian oil and gas leases.

The BLM has not yet published such a proposed rule, however.

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

The proposed rules for new and modified facilities are estimated to be finalized by the end of 2023, while any standards finalized for existing facilities will require further state rulemaking actions over the next several years before they become applicable and effective.

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

If finalized as proposed, the rule would limit gas that may be flared royalty-free during well completions, production testing, and emergencies;

establish a monthly volume limit on royalty-free flaring due to pipeline capacity constraints, midstream processing failures, or other similar events;

require vapor recovery systems on oil tanks;

require operators to maintain leak detection and repair (“LDAR”) programs;

prohibit the use of certain natural-gas-activated pneumatic controllers and pneumatic diaphragm pumps;

and require operators to submit waste minimization plans with applications for permit to drill, among other requirements.

In 2019, the EPA increased the state of Colorado’s non-attainment ozone classification for the Denver Metro North Front Range Ozone Eight-Hour Non-Attainment (“ Denver Metro/North Front Range NAA ”) area from “moderate” to “serious” under the 2008 national ambient air quality standard (“ NAAQS ”).

This increase in non-attainment status to “serious” triggered significant additional obligations for the state under the CAA and resulted in Colorado adopting new and more stringent air quality control requirements in December 2020 that are applicable to our operations.

Based on current air quality monitoring data, it is expected that the Denver Metro/North Front Range NAA will be further “bumped-up” to “severe” status in 2022.

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.

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

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

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

In effect, the petition for rulemaking calls for a blanket prohibition on oil and gas development in much of Colorado.

The COGCC denied the petition;

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

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

Commencing April 1, 2022, operators are required to reduce the annual volume of vented and flared natural gas in order to capture no less than ninety-eight percent of the natural gas produced from all wells by December 31, 2026.

(New Mexico Administrative Code Section 19.15.27.9).

This rule change is accompanied by additional reporting requirements for all flared and vented gas.

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In the past, Congress has considered proposed legislation to reduce emissions of GHGs.

To date, Congress has not adopted any such significant legislation, but may do so in the future.

In November 2021, the U.S.

House of Representatives passed H.R.5376, section 30114 which would amend the Clean Air Act to impose a fee of $1,500 per 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.

Senate is currently considering H.R.

5376 and may adopt, modify, or eliminate the methane fee.

The Obama administration reached an agreement during the December 2015 United Nations climate change conference in Paris pursuant to which the U.S.

initially pledged to make a 26 percent to 28 percent reduction in its GHG emissions by 2025, against a 2005 baseline, and committed to periodically update this pledge every five years starting in 2020 (the “ Paris Agreement ”).

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.

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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.

The adopted regulatory requirements are expected to become final and effective in early 2022.

Regulation of methane and other GHG emissions associated with oil and natural gas production could impose significant requirements and costs on our operations.

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Risk Factors .”

While there were no oil and gas ballot initiatives in 2022 that would have imposed additional regulations on the oil and gas industry in the State of Colorado, it is possible that future ballot initiatives will be proposed that could limit the areas of the state in which drilling would be permitted to occur or otherwise impose increased regulations on our industry.

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

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On January 20, 2021, the Acting U.S.

Interior Secretary, instituted a 60-day moratorium on new oil and gas leases and permits on federal onshore and offshore lands.

Interior Secretary, instituted a moratorium on new oil and gas leases and permits on federal onshore and offshore lands, which a federal court blocked with a preliminary injunction in June 2021, which injunction is being appealed.

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

A total of approximately 26% of the Company’s acreage in New Mexico and 1% of the Company’s acreage in Colorado are located on federal lands.

While in November 2021, the Biden administration recommended an overhaul of the nation’s oil and gas leasing program to limit areas available for energy development, the administration did not recommend a continued moratorium on new oil and gas leasing at that time.

However, it is currently unclear whether future moratoriums will be imposed, what the recommended overhaul will be, and whether such actions herald the start of a change in federal policies regarding the grant of oil and gas permits 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.

Endangered Species and Migratory Birds Considerations

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Similar protections are offered to migrating birds under the Migratory Bird Treaty Act.

We may conduct operations on oil and natural gas leases in areas where certain species that are listed as threatened or endangered are known to exist and where other species, such as the lesser prairie chicken, that potentially could be listed as threatened or endangered under the ESA may exist.

We may conduct operations on oil and natural gas leases in areas where certain species that are listed as threatened or endangered are known to exist, including the lesser prairie chicken which is now considered endangered as of November 2022, and where other species that potentially could be listed as threatened or endangered under the ESA may exist.

Moreover, as a result of one or more agreements entered into by the U.S.

Fish and Wildlife Service, the agency is required to make a determination on listing of numerous species as endangered or threatened under the ESA pursuant to specific timelines.

The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures, time delays or limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce reserves.

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.

The identification or designation of the lesser prairie chicken as endangered, and previously unprotected species as threatened or endangered, in areas where underlying property operations are conducted, could cause us to incur increased costs arising from species protection measures, time delays or limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce reserves.

Currently, all net acres in our Permian Basin Asset have been designated as critical or suitable habitat for the lesser prairie chicken, which could adversely impact the pace of our development and the value of these leases.

In October 2015, the U.S.

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Risk Factors .”

Global Warming and Climate Change

Various state governments and regional organizations have enacted, or are considering enacting, new legislation and promulgating new regulations governing or restricting the emission of GHG, including from facilities, vehicles and equipment.

Legislative and regulatory proposals for restricting GHG emissions or otherwise addressing climate change could require us to incur additional operating costs and could adversely affect demand for the oil and natural gas that we sell or the cost of the equipment and other materials we use.

The potential increase in our operating costs could include new or increased costs to obtain permits, operate and maintain our equipment, install new emission controls on our equipment, pay taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program.

Additionally, the development of a federal renewable energy standard, or the development of additional or more stringent renewable energy standards at the state level could reduce the demand for the oil and gas we produce, thereby adversely impacting our earnings, cash flows and financial position.

A cap-and-trade program generally would cap overall greenhouse gas emissions on an economy-wide basis and require major sources of greenhouse gas emissions or major fuel producers to acquire and surrender emission allowances.

A federal cap and trade program or expanded use of cap and trade programs at the state level could impose direct costs on us through the purchase of allowances and could impose indirect costs by incentivizing consumers to shift away from fossil fuels.

In addition, federal or state carbon taxes could directly increase our costs of operation and similarly incentivize consumers to shift away from fossil fuels.

In addition, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in an increasing number of financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities.

Ultimately, this may make it more difficult and expensive for us to secure funding.

Members of the investment community have also begun to screen companies such as ours for sustainability performance, including practices related to greenhouse gases and climate change, before investing in our securities.

Any efforts to improve our sustainability practices in response to these pressures may increase our costs, and we may be forced to implement technologies that are not economically viable in order to improve our sustainability performance and to meet the specific requirements to perform services for certain customers.

These various legislative, regulatory and other activities addressing greenhouse gas emissions could adversely affect our business, including by imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations, which could require us to incur costs to reduce emissions of greenhouse gases associated with our operations.

Limitations on greenhouse gas emissions could also adversely affect demand for oil and gas, which could lower the value of our reserves and have a material adverse effect on our profitability, financial condition and liquidity.

Compliance with GHG laws or taxes could significantly increase our costs, reduce demand for fossil energy derived products, impact the cost and availability of capital and increase our exposure to litigation.

Such laws and regulations could also increase demand for less carbon intensive energy sources.

Our oil and gas properties are subject to hazards inherent in the oil and gas industry, such as accidents, blowouts, explosions, implosions, fires and oil spills.

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We consider our relations with our employees to be satisfactory.

The health and safety of our employees is our highest priority, and this is consistent with our operating philosophy.

Our safety focus is also evident in our response to the COVID-19 pandemic:

Adding work from home flexibility;

Adjusting attendance policies to encourage those who are sick to stay home;

Increasing cleaning protocols across all locations;

Initiating regular communication regarding impacts of the COVID-19 pandemic, including health and safety protocols and procedures;

Establishing new physical distancing procedures for employees who need to be onsite;

Providing additional personal protective equipment and cleaning supplies;

Implementing protocols to address actual and suspected COVID-19 cases and potential exposure;

Limiting all non-essential travel for all employees;

Encouraging masks to be worn in all locations where allowed by local law.

The development, attraction and retention of employees is a critical success factor for the Company.

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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