What changed in this filing

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Item 1. Business

2023-04-17 compared with 2022-04-21 · 112 added, 172 removed, 203 unchanged (58% of the section changed)

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We are an independent oil and natural gas company engaged in acquiring, developing, and producing oil and natural gas.

We presently own producing and non-producing

properties located primarily in Texas, and Oklahoma.

We presently own producing and non-producing properties located primarily in Texas, and Oklahoma.

All of our oil and gas properties and interests are located in the United States.

Through our subsidiaries Prime Operating Company, Eastern Oil Well Service Company and EOWS Midland Company, we act as operator and provide well-servicing support operations for many of the onshore oil and gas wells in which we have an interest, as well as for third parties.

Through our subsidiaries Prime Operating Company, Eastern Oil Well Service Company, and EOWS Midland Company, we act as operator and provide well-servicing support operations for many of the onshore oil and gas wells we operate, as well as for third parties.

We are also active in the acquisition of producing oil and gas properties through joint ventures with industry partners.

In addition, we own a 12.5% overriding royalty interest in over 30,000 acres in the state of West Virginia.

We are currently not receiving revenue from this asset, as development has not begun.

In addition, through a wholly owned offshore company, we own a 60-mile-long pipeline offshore on the shallow shelf of Texas, not currently in use.

We also hold a 33.3% interest in a limited partnership that owns a 138,000-square-foot retail shopping center on ten acres in Prattville, Alabama, which is on our books for $40 thousand.

There is currently no debt on the shopping center and it has approximately $500,000 of working capital on its balance sheet.

Additional Information

PrimeEnergy files or furnishes annual, quarterly and current reports, proxy statements and other documents with the SEC under the Securities Exchange Act of 1934 (the “Exchange Act”).

The SEC maintains a website (www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers, including PrimeEnergy, that file electronically with the SEC.

The Company makes available, free of charge, through its website (www.primeenergy.com) its Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and, if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after it electronically files such material with, or furnishes it to, the SEC.

In addition to the reports filed or furnished with the SEC, Pioneer publicly discloses information from time to time in its press releases.

Such information, including information posted on or connected to the Company’s website, is not a part of, or incorporated by reference in, this Report or any other document the Company files with or furnishes to the SEC.

Exploration, Development, and Recent Activities

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Our capital budget for the year is reflective of current commodity prices and has been established based on an expectation of available cash flows, with any cash flow deficiencies expected to be funded by borrowings under our revolving credit facility.

As we have done historically to preserve or enhance liquidity, we may adjust our capital program throughout the year, divest non-strategic

assets, or enter into strategic joint ventures.

In 2021, nine two-mile

horizontal wells operated by Apache in Upton County, Texas were completed in the third quarter of 2021 and three two-mile

horizontal wells operated by Ovintiv Mid-Continent

Inc, in Canadian County, Oklahoma were completed in the fourth quarter of 2021.

The Company has an average of 47.5% interest in the nine wells and 11.25% interest in the three wells completed with Ovintiv.

Since the start of our West Texas horizontal drilling program in 2015 and through the fourth quarter of 2021 the Company has participated in 77 horizontal wells in the Permian Basin, three of which were drilled in 2021 and, together with six other horizontals drilled in 2020, were completed and brought into production in late September or early October of 2021.

As of year-end,

the Company has invested approximately $129 MM in this drilling program.

All nine of the wells in this program completed in 2021, were previously designated as proved undeveloped in the 2020 year-end

reserves report.

Of the horizontal wells in this program, the Company has an average of 30.62% interest in 62 wells, and less than one percent interest in 15 wells.

In Upton County, West Texas, we are developing a contiguous 3,260 acre block with our joint venture partner, Apache Corporation.

In this block the Company has 2,600 leasehold acres with interest between 14% and 56% depending on the particular lease and depth being developed.

In 2018, eight successful wells were drilled horizontally in the Wolfcamp “B” of this block with the Company participating for 49% interest.

This is believed to be full development of the Wolfcamp “B” reservoir.

Together with Apache, we are planning development of the Upper Wolfcamp, Jo Mill, and Lower Spraberry reservoirs of this block.

These shallower reservoirs have been proven-up

on our offset 1,300 acre Kashmir tract.

It is expected that as many as 54 additional horizontals will be developed on this 3,260 acres in the near future.

This development is estimated to cost approximately $370.6 million, with the Company’s share being approximately $170.8 million.

In addition to the 54 prospective wells to be drilled for these three reservoirs, a fourth target reservoir, the Middle Spraberry, is also prospective for future development.

The potential of the Middle Spraberry on the 3,260 acre block is for 18 horizontal wells to be drilled and completed at a gross cost of approximately $126.3 million with the Company’s share being approximately $61.8 million.

The actual number of wells that are eventually drilled as well as the cost and the timing of drilling will vary based upon many factors, including commodity market conditions.

In addition to the 3,260 acre block being developed, as described above, the Company is also developing an offsetting 1,300 acre block in Upton County, Texas, with Apache Corporation as operator.

In the second quarter of 2019 three horizontal wells were completed and brought on production from reservoirs above the Middle Wolfcamp:

one in the Wolfcamp “A”, one in the Jo Mill, and one in the Lower Spraberry, confirming the economic viability of these reservoirs on our acreage.

Prime holds 47.5% working interest in these reservoirs.

As a result of the success of the initial three wells, nine new horizontals were completed in the third quarter of 2021.

Our average 47.5% share of the cost of these nine horizontal wells was approximately $26.7 million in total.

In addition to the Wolfcamp “A”, Jo Mill and Lower Spraberry that are now fully developed on the tract, four locations in the Middle Spraberry will be considered for future development at an estimated gross cost of approximately $30.2 million with the Company’s share being approximately $14.2 million.

Also in the Permian Basin of West Texas, we are developing a 965 acre block with ConocoPhillips in Martin County, Texas.

In 2016 and 2017, four horizontal wells were drilled and completed and put on production.

The Company owns 35% to 38% interest in this joint venture acreage and we have received drilling plans from ConocoPhilips for the drilling of four wells in the third quarter of 2022 that are likely to be 2.5-mile

The Company’s investment in these wells is expected to be $15 million.

In first quarter of 2022, the Company is participating for 10.3% interest with SEM Operating Company in the drilling of four 1.5 mile-long horizontal wells in Irion County, Texas.

We have also received proposals from BTA Oil Producers for the drilling of nine 2.5 mile-long horizontals this year in Reagan County, Texas where the Company intends to participate for its 50% interest in six of the wells and 31% interest in three wells.

Our expected investment in the drilling and completion of these wells is $40.5 million.

In Oklahoma, we are focused on development of our reserves in Canadian, Grady, Kingfisher, Garfield, Major, and Garvin counties where we have approximately 6,200 net leasehold acres in the Scoop/Stack Play.

In 2019, we participated for an average of 4.6% interest with Newfield Exploration in twelve successful wells in Canadian County on our Slash and Wallace tracts.

In 2021, we participated for 11.25% interest with Ovintiv Mid-Continent

in four wells on our Peters tract, in Canadian County.

Three of these wells were successfully completed in December 2021 and online in January 2022, while one well had completion issues and has been temporarily abandoned.

At today’s product prices, payout of the Company’s $2.2 million investment in these four wells is expected to be in approximately six months.

In the first quarter of 2022 the Company received and approved proposals from Ovintiv for four horizontal wells on our Bohlman tract, in the same area as the Peters tract.

The first of these wells is slated to spud April 3, 2022.

The Company will participate with 9.38% interest for approximately $1.8 million through completion which is expected in June.

We believe our 6,200 net leasehold acres has the resource potential to support the drilling of as many as 54 new horizontal wells based on an estimate of four wells per section:

two in the Mississippian and two in the

Woodford Shale.

Should we choose to participate in future development, our share of the capital expenditures would be approximately $36 million at an average 10% ownership level;

the Company will otherwise sell its rights for cash, or cash plus a royalty or working interest.

As we have done historically to preserve or enhance liquidity, we may adjust our capital program throughout the year, divest non-strategic assets, or enter into strategic joint ventures.

We are actively developing our leasehold acreage in West Texas and in Oklahoma and on track to drill and complete approximately 40 wells in 2023.

The following is a description of recent, current, and expected near-term drilling activities.

In 2021, The Company participated for 47.5% interest with Apache Corporation in the drilling of nine two-mile-long horizontal wells in Upton County, Texas, and with Ovintiv Mid-Continent for 11.25% interest in four two-mile horizontal wells in Canadian County, Oklahoma.

Twelve of these horizontal wells were completed and placed into production in the fourth quarter of 2021.

One of the Ovintiv wells, however, had a casing leak issue and has been temporarily abandoned.

The Company invested approximately $32 million in these thirteen wells.

In the first three quarters of 2022, the Company participated in eight horizontal wells.

Four of these wells are located in Irion County, West Texas, operated by SEM Operating Company, and four are located in Canadian County, Oklahoma, operated by Ovintiv Mid-Continent, Inc.

Our investment in these eight wells was approximately $4 million and all were brought on production in August of 2022.

In the fourth quarter of 2022, we began participation in the drilling of 20 horizontal wells located in West Texas operated by three different operators.

In Martin County, we are participating with ConocoPhillips in five 2.5-mile-long horizontal wells in which the Company has 20.83% interest with a planned capital investment of $12.1 million.

In Reagan County, we are participating with Hibernia Energy III in 10 two-mile horizontals with 25% interest and an expected investment of $25.6 million.

Also in Reagan County, we are participating with Double Eagle (DE IV) in five two-mile-long horizontals with nearly 50% interest, carrying an expected net capital outlay of $23.4 million.

All twenty of these West Texas wells are currently drilling or have been completed.

All are expected to be on line in the second quarter of 2023.

January of 2023, the Company joined Ovintiv USA, Inc.

in the spudding of three 3-mile-long horizontal wells in Canadian County, Oklahoma with 1.96% interest and an expected investment of $645,000.

Production is expected to begin in May 2023.

In addition, in March of 2023, Apache Corporation spud two 3-mile-long horizontals in Upton County, Texas in which the Company has 49.4% interest with an expected total capital investment of $16.1 million.

We anticipate completion of these two 15,000’ long horizontals in Upton County in May and production to occur in June of 2023.

In total, the Company expects to invest $78 million in these 25 horizontal wells.

In December 2022, we prepaid $32 million toward drilling costs, and the remaining $46 million in estimated drilling and completion expenses will be incurred in 2023.

All 25 wells are expected to be completed and on-line in the second quarter of 2023.

We anticipate that success from the 22 horizontals in West Texas described above will lead to additional near-term horizontal drilling covering five leasehold blocks in three counties of West Texas:

26 additional 10,000’ long horizontals in Reagan County from Hibernia, Double Eagle, and BTA Oil Producers (or its successor in the South Stiles Project), ten additional 12,500’ long horizontals in Martin County by ConocoPhillips, and six additional 15,000’ long horizontals in Upton County by Apache.

These anticipated additional 42 drilling proposals will target various proven pay intervals of the Wolfcamp and Spraberry formations and will require an estimated $200 million in net capital investment through 2024.

identified 27 horizontal locations that would be a natural progression of development for three of these project areas in Upton and Reagan counties.

These 27 wells are anticipated to be drilled in the 2025-2026 timeframe and would require net investment of approximately $100 million.

In total, with the $78 million current investment in 22 wells, the $200,000 near-term investment in 42 wells, and the $100 million in 27 subsequent drill sites, we are planning for an investment of approximately $400 million in horizontal development over the next several years.

In the Permian Basin of West Texas and eastern New Mexico we maintain an acreage position of approximately 16,940 gross (9,969 net) acres, 96.5% of which is located in Reagan, Upton, Martin, and Midland counties of Texas where our current West Texas horizontal drilling activities are focused.

We believe this acreage has the resource potential to support the drilling of as many as 190 future horizontal wells following the active 22 and anticipated 42 horizontal wells described above.

In Oklahoma, we are focused on the development of our reserves in Canadian, Grady, Kingfisher, Garfield, Major, and Garvin counties where we have approximately 4,113 net leasehold acres in the Scoop/Stack Play.

Of this acreage, we believe 2,355 net leasehold acres hold significant additional resource potential that could support the drilling of as many as 46 new horizontal wells based on an estimate of four wells per multi-section drilling unit, two in the Mississippian and two in the Woodford Shale.

In the near term, we anticipate nine new drilling proposals to be received with an estimated net expense of $5.2 million covering 338 net leasehold acres.

Proposals may be received on the remaining 2,017 acres, however, rather than participate we may choose to sell the acreage or farm-out, receiving cash and retaining an over-riding royalty interest.

Significant Activity

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Total expenditures for the acquisition, exploration, and development of our properties during 2022 were $14.0 million as we continue development under the programs discussed above.

Proved reserves as of December 31, 2021, were 12.5 MMBOE which consisted of 100% proved developed reserves.

During 2021, we participated in the drilling of seven gross horizontal wells and the completion of 12 horizontal wells.

Three of these were completed in September along with six other horizontal wells drilled in 2020 on the same lease in Upton County, Texas.

All nine were put online and began production in late September and early October 2021.

Four of the horizontals drilled in 2021 are located in Canadian County, Oklahoma;

of these, three were completed in December 2021 and brought online in the first week of January 2022, while a fourth had mechanical issues and has been temporarily abandoned.

The Company has 47.5% interest in the nine horizontals located in Upton County, Texas, and 11.25% interest in the four horizontals located in Canadian County, Oklahoma.

In 2021, the Company sold 116 net acres in Martin County Texas, receiving gross proceeds of approximately $1.45 million, while in this same year acquiring 5.9 net acres in Upton County, Texas for $29,500 in an area where the Company currently has leasehold acreage and potential future horizontal drilling.

In the first quarter of 2022, the Company has sold 1809 net leasehold acres in Reagan and Midland Counties, Texas through two separate transactions receiving gross proceeds of $14.1 million.

With the culmination of these sales the Company has reduced its bank debt to $9 million as of March 31, 2022, has the right to borrow up to $50 million under its current revolving line of credit.

Proved reserves as of December 31, 2022, were 16,718 MBOE which consisted of 62% proved developed reserves and 38% proved undeveloped reserves.

During the first three quarters of 2022, the Company participated in the drilling and completion of eight completed horizontal wells put into production in August 2022.

The Company participated with a 9% interest in four horizontals located in Canadian County, Oklahoma, operated by Ovintiv Mid-Continent, Inc., and with a 10.13% interest in four wells located in Irion County, Texas, operated by SEM Operating Company.

The Company is actively participating in 25 horizontals, 22 of which are in the West Texas Spraberry and Wolfcamp trend and three of which are in the Oklahoma Scoop Stack play.

In total, the Company will invest approximately $78 million in these 25 horizontals that are expected to be in production in the second quarter of 2023.

Additional development on these same leasehold blocks and adjacent Company owned blocks is anticipated in the second half of 2023 and 2024.

In 2022, the Company entered into an agreement with Double Eagle to create a 2,560-acre AMI for the joint development of horizontal wells;

as part of this agreement, the Company sold a portion of its interest in this acreage for proceeds of $16.1 million.

In addition, in 2022, we sold 240 net acres in Reagan County to BTA Oil Producers for proceeds of $1.8 million, and we sold 353 net acres in Canadian County, Oklahoma to Paloma Partners, IV, Inc.

for $1.3 million.

Through three other transactions, we divested a minor tract in Lea County, NM for a nominal cash consideration and assigned nine wellbores in West Texas to a third-party operator in exchange for a reduction in our future plugging liability.

In this same year, the Company acquired 3.2 net mineral acres in Upton County, Texas for $16,000.

We believe that our diversified portfolio approach to our drilling activities produces more consistent and predictable economic results than would otherwise be experienced with a less diversified or higher-risk drilling program profile.

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Our main objective in making any such acquisitions will be to acquire income-producing assets to increase our net worth and increase our oil and gas reserve base.

We presently own producing and non-producing

properties located primarily in Texas, and Oklahoma, and we own a substantial amount of well servicing equipment.

We do not own any refinery or marketing facilities;

and do not currently own or lease any bulk storage facilities or pipelines other than adjacent to and used in connection with producing wells and the interests in certain gas gathering systems.

We presently own producing and non-producing properties located primarily in Texas, and Oklahoma, and we own a substantial amount of well-servicing equipment.

We do not own any refinery or marketing facilities and do not currently own or lease any bulk storage facilities or pipelines other than adjacent to and used in connection with producing wells and the interests in certain gas gathering systems.

All of our oil and gas properties and interests are located in the United States.

In the past, the supply of gas has exceeded demand on a cyclical basis, and we are subject to a combination of shut-in

and/or reduced takes of gas production during summer months.

Prolonged shut-ins

could result in reduced field operating income from properties in which we act as operator.

In the past, the supply of gas has exceeded demand on a cyclical basis, and we are subject to a combination of shut-ins and/or reduced takes of gas production during summer months.

Prolonged shut-ins could result in reduced field operating income from properties in which we act as operator.

Exploration for oil and gas requires substantial expenditures, particularly in exploratory drilling in undeveloped areas, or “wildcat drilling.” As is customary in the oil and gas industry, substantially all of our exploration and development activities are conducted through joint drilling and operating agreements with others engaged in the oil and gas business.

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96 through the Houston office, 316 through the Midland office, and 216 through the Oklahoma City office.

Substantially all of the wells we operate are wells in which we have an interest.

We operate wells pursuant to operating agreements that govern the relationship between us, as operator, and the other owners of working interests in the properties, including the Partnerships, Trusts and joint venture participants.

We own a majority interest in nearly all of our operated wells.

We operate wells according to operating agreements that govern the relationship between us, as operator, and the other owners of working interests in the properties and joint venture participants.

For each operated well, we receive monthly fees that are competitive in the areas of operations and we also are reimbursed for expenses incurred in connection with well operations.

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Failure to comply with applicable laws and regulations can result in substantial penalties.

The regulatory burden on the industry increases the cost of doing business and affects profitability.

The regulatory burden on the industry

increases the cost of doing business and affects profitability.

Although we believe we are in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted.

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As described above, natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations.

In addition, all of the jurisdictions in which we own or operate producing oil and natural gas properties have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling

and completion process and the abandonment of wells.

Our operations are also subject to various conservation laws and regulations.

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These statutes may affect whether and to what extent gathering capacity is available for oil and natural gas production, if any, of the drilling program and the cost of such capacity.

Further, state laws and regulations govern rates and terms of access to intrastate pipeline systems, which may similarly affect market access and cost.

The FERC regulates interstate natural gas pipeline transportation rates and service conditions.

The FERC regularly proposes and implements new rules and regulations affecting interstate transportation.

The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and to promote market transparency.

We do not believe that such FERC action would have a material disproportionate effect on our drilling program as compared to other similarly situated natural gas producers.

Gathering services, which occur upstream of FERC jurisdictional transmission services, and which are performed onshore and in state-controlled waters are regulated by state governments.

Although the FERC has set forth a general test for determining whether facilities perform a non-jurisdictional

gathering function or a jurisdictional transmission function, the FERC’s determinations as to the classification of facilities is conducted on a case-by-case

State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements.

Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

In addition to the regulation of natural gas pipeline transportation, the FERC has jurisdiction over the purchase or sale of gas or the purchase or sale of transportation services subject to the FERC’s jurisdiction pursuant to the Energy Policy Act of 2005.

Under this law, it is unlawful for “any entity,” including a producer such as us, that is otherwise not subject to the FERC’s jurisdiction under the Natural Gas Act of 1938 to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of gas, or the purchase or sale of transportation services subject to regulation by the FERC, in contravention of rules prescribed by the FERC.

The FERC’s rules implementing this provision make it unlawful, in connection with the purchase or sale of gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud, to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading, or to engage in any act or practice that operates as a fraud or deceit upon any person.

The Energy Policy Act of 2005 also gives the FERC authority to impose civil penalties for violations of the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978 up to $1,291,894 per day per violation (adjusted annually based on inflation) and disgorge profits associated with any violation.

The anti-manipulation rule applies to activities of otherwise non-jurisdictional

entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which includes the annual reporting requirements under Order 704 (defined below).

In December 2007, the FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (“Order 704”).

Under Order 704, any market participant that engages in wholesale sales or purchases of gas that equal or exceed 2.2 million MMBtus of physical natural gas in the previous calendar year, must annually report such sales and purchases to the FERC on Form No.

552 on May 1 of each year.

552 contains aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize or contribute to the formation of price indices.

It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704.

Order 704 is intended to increase the transparency of the wholesale gas markets and to assist the FERC in monitoring those markets and in detecting market manipulation.

The FERC also regulates rates and service conditions for the interstate transportation of liquids, including oil and NGLs, under the Interstate Commerce Act (the “ICA”).

Prices received from the sale of liquids may be affected by the cost of transporting those products to market.

The ICA requires that pipelines maintain a tariff on file with the FERC.

The tariff sets forth the established rates as well as the rules and regulations governing the service.

The ICA requires, among other things, that rates and terms and conditions of service on interstate common carrier pipelines be “just and reasonable.” Such pipelines must also provide jurisdictional service in a manner that is not unduly discriminatory or unduly preferential.

Shippers have the power to challenge new and existing rates and terms and conditions of service before the FERC.

Rates of interstate liquids pipelines are currently regulated by the FERC primarily through an annual indexing methodology, under which pipelines increase or decrease their rates in accordance with an index adjustment specified by the FERC.

For the five-year period beginning on July 1, 2016, the FERC established an annual index adjustment equal to the change in the producer price index for finished goods plus 1.23%.

This adjustment is subject to review every five years.

Under the FERC’s regulations, a liquids pipeline can request the authority to charge market-based rates for transportation service if it satisfies certain criteria, and also can request a rate increase that exceeds the rate obtained through application of the indexing methodology by using a cost-of-service

approach, but only after the pipeline establishes that a substantial divergence exists between the actual costs experienced by the pipeline and the rates resulting from application of the indexing methodology.

Increases in liquids transportation rates may result in lower revenue and cash flows.

In addition, due to common carrier regulatory obligations of liquids pipelines, capacity must be prorated among shippers in an equitable manner in the event there are nominations in excess of capacity.

Therefore, requests for service by new shippers or increased volume by existing shippers may reduce the capacity available to us.

Any prolonged interruption in the operation or curtailment of available capacity of the pipelines that we

rely upon for liquids transportation could have a material adverse effect on our business, financial condition, results of operations and cash flows.

However, we believe that access to liquids pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.

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

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

We believe that the regulation of liquids pipeline transportation rates will not affect our operations in any way that is materially different from the effects on our similarly situated competitors.

In addition to the FERC’s regulations, we are required to observe anti-market manipulation laws with regard to our physical sales of energy commodities.

In November 2009, the Federal Trade Commission (the “FTC”) issued regulations pursuant to the Energy Independence and Security Act of 2007 intended to prohibit market manipulation in the petroleum industry.

Violators of the regulations face civil penalties of up to $1,231,690 per violation per day (adjusted annually based on inflation).

In July 2010, Congress passed the Dodd-Frank Act, which incorporated an expansion of the authority of the Commodity Futures Trading Commission (the “CFTC”) to prohibit market manipulation in the markets regulated by the CFTC.

This authority, with respect to crude oil swaps and futures contracts, is similar to the anti-manipulation authority granted to the FTC with respect to crude oil purchases and sales.

In July 2011, the CFTC issued final rules to implement its new anti-manipulation authority.

The rules subject violators to a civil penalty of up to the greater of $1,212,866 (adjusted annually based on inflation) or triple the monetary gain to the person for each violation.

Further, state laws and

regulations govern rates and terms of access to intrastate pipeline systems, which may similarly affect market access and cost.

To the extent that the Company enters into transportation contracts with pipelines that are subject to the United States Federal Energy Regulatory Commission (“FERC”) regulation, the Company is subject to FERC requirements related to use of such capacity.

Any failure on the Company’s part to comply with FERC’s regulations and policies related to pipeline transportation, reporting requirements or other regulations, and any failure to comply with a FERC-related pipeline’s tariff, could result in the imposition of civil and criminal penalties.

In addition, any changes in FERC or state regulations or requirements on pipeline transportation may result in increased transportation costs on pipelines that are subject to such regulation, thereby negatively impacting the Company’s profitability.

Regulation of Environmental and Occupational Safety and Health Matters

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Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant impact on our operating costs.

of enforcement policies that result in more stringent and costly waste handling, storage, transportation, disposal, or remediation requirements could have a material adverse effect on our financial position and results of operations.

The clear trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment and thus any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly waste handling, storage, transportation, disposal, or remediation requirements could have a material adverse effect on our financial position and results of operations.

We may be unable to pass on such increased compliance costs to our purchasers.

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The Resource Conservation and Recovery Act

The Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous

Pursuant to rules issued by the U.S.

Environmental Protection Agency (the “EPA”), individual state governments administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements.

Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of crude oil or natural gas are currently regulated under RCRA’s non-hazardous

waste provisions.

However, it is possible that certain oil and natural gas drilling and production wastes now classified as non-hazardous

could be classified as hazardous wastes in the future.

However, it is possible that certain oil and natural gas drilling and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future.

A change in the classification of exploration and production wastes has the potential to significantly increase our waste disposal costs to manage, which in turn will result in increased operating costs and could adversely impact our results of operations and financial position.

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In addition, we currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration, production and processing for many years.

Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site

locations, where such substances have been taken for disposal.

In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control.

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presidential administrations.

Currently, the WOTUS rule is active in 22 states and enjoined in 28 states.

Currently, the WOTUS rule is active in

22 states and enjoined in 28 states.

However, in December 2018, the EPA and the USACE proposed changes to regulations under the CWA that would provide discrete categories of jurisdictional waters and tests for determining whether a particular waterbody meets any of those classifications.

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To the extent the original WOTUS rule or any replacement rule expands the scope of the CWA’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.

In addition, federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance

with discharge permits or other requirements of the CWA and analogous state laws and regulations.

In addition, federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

We do not expect the costs to comply with the requirements of the CWA to have a material adverse effect on our operations.

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The RRC requires operators to obtain a permit from the agency for the operation of saltwater disposal wells and establishes minimum standards for injection well operations.

In response to recent seismic events near underground injection wells used for the disposal of oil and natural gas-related

waste waters, federal and some state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have shut down or placed volumetric injection limits on existing wells or imposed moratoria on the use of such injection wells.

In response to recent seismic events near underground injection wells used for the disposal of oil and natural gas-related waste waters, federal and some state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have shut down or placed volumetric injection limits on existing wells or imposed moratoria on the use of such injection wells.

In response to concerns related to induced seismicity, regulators in some states have already adopted or are considering additional requirements related to seismic safety.

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The federal Clean Air Act and comparable state laws restrict the emission of air pollutants from many sources, such as tank batteries and compressor stations, through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements.

These laws and regulations may require us to obtain pre-approval

for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants.

These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants.

Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues.

For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard for ozone from 75 to 70 parts per billion.

The EPA approved final attainment/nonattainment designations with the new ozone standards in July 2018 and currently all of the areas in which we operate are in attainment with such standards.

The EPA approved final attainment/nonattainment

designations with the new ozone standards in July 2018 and currently all of the areas in which we operate are in attainment with such standards.

However, state implementation of these revised air quality standards or a change in the attainment status of the areas in which we operate 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.

Separately, in June 2016, the EPA finalized a rule regarding criteria for aggregating multiple small surface sites into a single source for air-quality

permitting purposes applicable to the oil and natural gas industry.

Separately, in June 2016, the EPA finalized a rule regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and natural gas industry.

This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements, which in turn could result in operational delays or require us to install costly pollution control equipment.

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Also, as noted above, the EPA has promulgated a New Source Performance Standard related to methane emissions from the oil and natural gas source category.

While Congress has considered legislation related to the reduction of GHG emissions in the past, no significant legislation to reduce GHG emissions has been adopted at the federal level.

In the absence of

Congressional action, a number of state and regional GHG restrictions have emerged.

At the international level, the United States joined the international community at the 21 st

Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France.

The Paris Agreement entered into force in November 2016.

Although this agreement does not create any binding obligations for nations to limit their GHG emissions, it does include pledges from participating nations to voluntarily limit or reduce future emissions.

In June 2017, President Trump stated that the United States would withdraw from the Paris Agreement, but may enter into a future international agreement related to GHGs.

The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020.

The United States’ adherence to the exit process is uncertain, and the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time.

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations.

Substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce and lower the value of our reserves.

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We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities.

Nonetheless, if new or more

stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we may be required to incur significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities and perhaps even be precluded from drilling wells.

Nonetheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we may be required to incur significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities and perhaps even be precluded from drilling wells.

If new federal, state or local laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could result in delays, eliminate certain drilling and injection activities and make it more difficult or costly to perform fracturing.

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Moreover, as a result of a 2011 settlement agreement, the FWS was required to make a determination on listing of more than 250 species as endangered or threatened under the FSA 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.

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

pursuant to the settlement agreement.

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

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We are subject to the requirements of the Occupational Safety and Health Administration (“OSHA”) and comparable state statutes whose purpose is to protect the health and safety of workers.

In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know

Act and comparable state statutes and any implementing regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens.

In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act and comparable state statutes and any implementing regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens.

Related Permits and Authorizations

Many environmental laws require us to obtain permits or other authorizations from state and/or federal agencies before initiating certain drilling, construction, production, operation, or other oil and natural gas activities and to maintain these permits and compliance with their requirements for on-going

These permits are generally subject to protest, appeal, or litigation, which, in certain cases, can delay or halt projects and cease production or operation of wells, pipelines and other operations.

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Although we have not experienced any material adverse effect from compliance with environmental requirements, there is no assurance that this will continue.

We did not have any material capital or other non-recurring

expenditures in connection with complying with environmental laws or environmental remediation matters in 2021, nor do we anticipate that such expenditures will be material in 2022.

We did not have any material capital or other non-recurring expenditures in connection with complying with environmental laws or environmental remediation matters in 2022, nor do we anticipate that such expenditures will be material in 2023.

Competition and Markets

The business of acquiring producing properties and non-producing

leases suitable for exploration and development is highly competitive.

Our competition, in our efforts to acquire both producing and non-producing

properties, include oil and gas companies, independent concerns, income programs and individual producers and operators, many of which have financial resources, staffs and facilities substantially greater than those available to us.

The business of acquiring producing properties and non-producing leases suitable for exploration and development is highly competitive.

Our competition, in our efforts to acquire both producing and non-producing properties, include oil and gas companies, independent concerns, income programs and individual producers and operators, many of which have financial resources, staffs and facilities substantially greater than those available to us.

Furthermore, domestic producers of oil and gas must not only compete with each other in marketing their output, but must also compete with producers of imported oil and gas and alternative energy sources such as coal, nuclear power and hydroelectric power.

Competition among petroleum companies for favorable oil and gas properties and leases can be expected to increase.

The Company also faces competition from companies that supply alternative sources of energy, such as wind, solar and other renewables.

Competition will increase as alternative energy technology becomes more reliable and governments throughout the world support or mandate the use of such alternative energy,

The availability of a ready market for any oil and gas produced by us at acceptable prices per unit of production will depend upon numerous factors beyond our control, including the extent of domestic production and importation of oil and gas, the proximity of our producing properties to gas pipelines and the availability and capacity of such pipelines, the marketing of other competitive fuels, fluctuation in demand, governmental regulation of production, refining, transportation and sales, general national and worldwide economic conditions, and use and allocation of oil and gas and their substitute fuels.

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however, hedging arrangements may expose us to risk of financial loss in some circumstances and may limit the benefit we would receive from increases in the prices for oil, natural gas and NGLs.

Oil and Gas Industry Considerations

The COVID-19 pandemic resulted in a severe worldwide economic downturn, significantly disrupting the demand for oil throughout the world, and created significant volatility, uncertainty and turmoil in the oil and gas industry.

The decrease in demand for oil, combined with excess supply of oil and related products, resulted in oil prices declining significantly beginning in late February 2020.

Since mid-2020, oil prices have improved, with demand steadily increasing despite the uncertainties surrounding the COVID-19 variants, and related responses by governments worldwide with regards to travel restrictions, business closures and other restrictions, which have continued to inhibit a full global demand recovery.

In addition, worldwide oil inventories, from a historical perspective, remain low and concerns exist with the ability of OPEC and other oil producing nations to meet forecasted future oil demand growth, with many OPEC countries not able to produce at their OPEC agreed upon quota levels due to their limited capital investments directed towards developing incremental oil supplies over the past few years.

Furthermore, sanctions, import bans and price caps on Russia have been implemented by various countries in response to the war in Ukraine, further impacting global oil supply.

As a result of these and other oil and gas supply constraints, the world has experienced significant increases in energy costs.

During December 2022, OPEC announced a continuation of its 2 MMBOPD production cut that started in November 2022 related to the uncertainty surrounding the global economy and future oil demand.

As a result of the current global supply and demand imbalances, oil and gas prices have remained strong with average NYMEX oil and NYMEX gas prices for the three months ended December 31, 2022 being $82.64 per Bbl and $6.26 per Mcf, respectively, as compared to $77.19 per Bbl and $5.84 per Mcf, respectively, for the same period in 2021.

In addition, the ongoing pandemic, combined with the Russia/Ukraine conflict, has resulted in global supply chain disruptions, which has led to significant cost inflation and the potential for a global recession.

Specifically, the Company’s 2022 capital program was impacted by higher than expected inflation in steel, diesel and chemical prices, among other items.

Global oil price levels and inflationary pressures will ultimately depend on various factors that are beyond the Company’s control, such as (i) the ability of OPEC and other oil producing nations to manage the global oil supply, (ii) the impact of sanctions and import bans on production from Russia, (iii) the timing and supply impact of any Iranian sanction relief on their ability to export oil, (iv) the effectiveness of responses by businesses and governments to combat any additional outbreaks of the COVID-19 virus and their impact on domestic and worldwide demand, (v) the global supply chain constraints associated with manufacturing and distribution delays, (vi) oilfield service demand and cost inflation, (vii) political stability of oil consuming countries and (viii) increasing expectations that the world may be heading into a global recession.

The Company continues to assess and monitor the impact of these factors and consequences on the Company and its operations.

Major Customers

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Apache Corporation

Targa Pipeline Mid-Continent

West Tex, LLC

Targa Pipeline Mid-Continent West Tex, LLC

Although there are no long-term purchasing agreements with these purchasers, we believe that they will continue to purchase our oil and gas products and, if not, could be readily replaced by other purchasers.

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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