EDGAR 10-K Filing

Company CIK: 56868
Filing Year: 2022
Filename: 56868_10-K_2022_0001193125-22-113187.json

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ITEM 1. BUSINESS
Item 1.
BUSINESS.
General
PrimeEnergy Resources Corporation (the “Company”) was organized in March, 1973, under the laws of the State of Delaware.
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. 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. We are also active in the acquisition of producing oil and gas properties through joint ventures with industry partners.
Exploration, Development and Recent Activities
The Company’s activities include development and exploratory drilling. Our strategy is to develop the Company’s extensive oil and gas reserves primarily through horizontal drilling. This strategy includes targeting reservoirs with high initial production rates and cash flow as well as targeting reservoirs with lower initial production rates but with higher expected return on investment. We believe that with today’s technology, horizontal development of our reserves provides superior economic results as compared to vertical development, by delivering higher production rates through greater contact and stimulation of a larger volume of reservoir rock while minimizing the surface footprint required to develop those same reserves.
Maintaining a strong balance sheet and ample liquidity are key components of our business strategy. In 2022, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. 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
laterals. 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
Inc. 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.
Significant Activity
As of December 31, 2021, we had net capitalized costs related to proved oil and gas properties of $179.7 million. Total expenditures for the acquisition, exploration, and development of our properties during 2021 were $18.7 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.
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.
We attempt to assume the position of operator in all acquisitions of producing properties. We will continue to evaluate prospects for leasehold acquisitions and for exploration and development operations in areas in which we own interests and are actively pursuing the acquisition of producing properties. To diversify and broaden our asset base, we will consider acquiring the assets or stock in other entities and companies in the oil and gas business. 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. 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.
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.
Summaries of our oil and gas drilling activities, oil and gas production, and undeveloped leasehold, mineral, and royalty interests are set forth under Item 2., “Properties”, below. Summaries of our oil and gas reserves, future net revenue and present value of future net revenue are also set forth under Item 2., “Properties-Reserves”, below.
Well Operations
Our operations are conducted through our principal offices in Houston, Texas, and district offices in Houston and Midland, Texas, and Oklahoma City, Oklahoma. We currently operate 710 wells, including producing, saltwater disposal, injection, and supply wells: 144 through the Houston office, 327 through the Midland office, and 239 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. 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.
The Partnerships, Trusts and Joint Ventures
Since 1975, PEMC acted as managing general partner of various partnerships, trusts and joint ventures. As we entered into 2021, we had one partnership and one trust remaining. During 2021 the remaining partnership and trust were liquidated.
Regulation
Regulation of the Oil and Natural Gas Industry
Our operations are substantially affected by federal, state and local laws and regulations. Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by the United States Congress (“Congress”), state governments, the Federal Energy Regulatory Commission (the “FERC”) and other federal and state regulatory agencies and federal, state and local courts. We cannot predict when or whether any such proposals may become effective. We do not believe that such action or proposal would have a material disproportionate effect on us as compared to similarly situated competitors.
Regulation Affecting Production
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. These include the regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in an area and the unitization or pooling of crude oil or natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells. These laws and regulations may limit the number of oil and natural gas wells we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but there can be no assurance that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells or limit the number of locations we can drill.
The failure to comply with the rules and regulations of oil and natural gas production and related operations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.
Regulation Affecting Sales and Transportation of Commodities
Sales prices for oil, natural gas and NGLs are not currently regulated and therefore are dictated by the prevailing market prices. Although prices of these energy commodities are currently unregulated, Congress historically has been active in their regulation. We cannot predict whether new legislation to regulate oil and natural gas, or the prices charged for these commodities, might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, the proposals might have on our operations. Sales of oil and natural gas may be subject to certain state and federal reporting requirements.
The price and terms of service of transportation of commodities, including access to pipeline transportation capacity, are subject to extensive federal and state regulation. Such regulation may affect the marketing of oil and natural gas produced, as well as the revenues received for sales of such production. Gathering systems may be subject to state ratable take statutes and common purchaser statutes. Ratable take statutes generally require gatherers to take, without undue discrimination, oil and natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase, or accept for gathering, without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes may affect whether and to what extent gathering capacity is available for oil and natural gas production, if any, of the drilling program and the cost of such capacity. Further, state laws and regulations govern rates and terms of access to intrastate pipeline systems, which may similarly affect market access and cost.
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
basis. 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. Form No. 552 contains aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize 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.
Regulation of Environmental and Occupational Safety and Health Matters
Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment and occupational health and safety. These laws and regulations may, among other things: (i) require the acquisition of permits to conduct exploration, drilling and production operations; (ii) restrict the types, quantities and concentration of various substances that can be released into the environment or injected into formations in connection with oil and natural gas drilling and production activities; (iii) limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; (iv) require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells; and (v) impose substantial liabilities for pollution resulting from drilling and production operations. Any failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of corrective or remedial obligations and the issuance of orders enjoining performance of some or all of our operations.
These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. 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.
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. Moreover, accidental releases or spills may occur in the course of our operations and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. While compliance with existing environmental laws and regulations has not had a material adverse effect on our operations to date, we can provide no assurance that this will continue in the future.
The following is a summary of the more significant existing and proposed environmental, occupational health and safety laws and regulations to which our business operations are or may be subject to and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.
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
wastes. 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. 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. Also, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as hazardous wastes if such wastes have hazardous characteristics.
Comprehensive Environmental Response, Compensation and Liability Act
The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and former owners and operators of the site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We generate materials in the course of our operations that may be regulated as hazardous substances. Despite the “petroleum exclusion” of CERCLA, which currently encompasses natural gas, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment. 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. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state and local laws. Under such laws, we could be required to undertake investigatory, response, or corrective measures, which could include soil and groundwater sampling, the removal of previously disposed substances and wastes, the cleanup of contaminated property, or remedial plugging or pit closure operations to prevent future contamination, the costs of which could be substantial.
Water Discharges
The Federal Water Pollution Control Act, or the Clean Water Act (the “CWA”), and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters, including wetland areas, is prohibited, except in accordance with the terms of a permit issued by the EPA, the U.S. Army Corps of Engineers (the “USACE”) or an analogous state agency. In September 2015, the EPA and the USACE issued a final rule redefining the scope of the EPA’s and the USACE’s jurisdiction under the CWA with respect to certain types of waterbodies and classifying these waterbodies as regulated wetlands (the “WOTUS” rule). Several legal challenges to the rule followed, along with attempts to stay implementation of the WOTUS rule following the change in U.S. presidential administrations. 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. Several groups have already announced their intent to challenge the proposed WOTUS replacement rule. Therefore, the scope of jurisdiction under the CWA is uncertain at this time. 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. We do not expect the costs to comply with the requirements of the CWA to have a material adverse effect on our operations.
The Oil Pollution Act of 1990 amends the CWA and establishes strict liability for owners and operators of facilities that cause a release of oil into waters of the United States. In addition, this law requires owners and operators of facilities that store oil above specified threshold amounts to develop and implement spill prevention, control and countermeasures plans.
Safe Drinking Water Act and Saltwater Disposal Wells
In the course of our operations, we produce water in addition to oil and natural gas. Water that is not recycled or otherwise disposed of on the lease may be sent to saltwater disposal wells for injection into subsurface formations. Underground injection operations are regulated under the federal Safe Drinking Water Act and permitting and enforcement authority may be delegated to state governments. In Texas, the Texas Railroad Commission (“RRC”) regulates the disposal of produced water by injection well. 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 concerns related to induced seismicity, regulators in some states have already adopted or are considering additional requirements related to seismic safety. For example, the RRC has adopted rules for injection wells to address these seismic activity concerns in Texas. Among other things, the rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells and allow the RRC to modify, suspend, or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. More stringent regulation of injection wells could lead to reduced construction or the capacity of such wells, which could in turn impact the availability of injection wells for disposal of wastewater from our operations. Increased costs associated with the transportation and disposal of produced water, including the cost of complying with regulations concerning produced water disposal, may reduce our profitability. The costs associated with the disposal of proposed water are commonly incurred by all oil and natural gas producers, however, and we do not believe that these costs will have a material adverse effect on our operations.
Air Emissions
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. 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. 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. 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. The EPA has also adopted new rules under the Clean Air Act that require the reduction of volatile organic compound emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors and from pneumatic controllers and storage vessels. The EPA expanded on its emission standards for volatile organic compounds in June 2016 with the issuance of first-time standards, known as Subpart OOOOa, to address emissions of methane from equipment and processes across the oil and natural gas source category, including hydraulically fractured oil and natural gas well completions. Following the change in presidential administration, there have been attempts to modify these regulations, and litigation concerning the regulations is ongoing. As a result of these developments, substantial uncertainty exists with respect to implementation of the EPA’s 2016 methane rule. However, given the long-term trend toward increasing regulation, future federal methane regulation of the oil and gas industry remains a possibility, and several states have separately imposed their own regulations on methane emissions from oil and gas production activities. These and other air pollution control and permitting requirements have the potential to delay the development of oil and natural gas projects and increase our costs of development and production, which costs could be significant. We do not believe that compliance with such requirements, however, will have a material adverse effect on our operations.
Regulation of Greenhouse Gas Emissions
In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) endanger public health and the environment, the EPA has adopted regulations under existing provisions of the Clean Air Act that, among other things, establish Prevention of Significant Deterioration (“PSD”), construction and Title V operating permit reviews for certain large stationary sources. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards for these emissions. EPA rulemakings related to GHG emissions could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the annual reporting of GHG emissions from certain petroleum and natural gas system sources in the U.S., including, among others, onshore and offshore production facilities, which include certain of our operations. 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 21st
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. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to represent a major share of global energy use through 2040, and other private sector studies project continued growth in demand for the next two decades. However, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector. Finally, it should also be noted that many scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts and other climatic events; if any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.
Hydraulic Fracturing Activities
Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemicals under pressure into target geological formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations. Recently, there has been increased public concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies, resulting in new legislative and regulatory initiatives that seek to increase the regulatory burden imposed on hydraulic fracturing.
At the federal level, the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities. Further, the EPA finalized regulations under the CWA in June 2016 that prohibit wastewater discharges from hydraulic fracturing and certain other natural gas operations to publicly owned wastewater treatment plants. Also, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain limited circumstances.
At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. For example, in May 2013, the RRC adopted new rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of, or prohibiting, drilling or hydraulic fracturing activities. 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.
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. Any such regulations limiting or prohibiting hydraulic fracturing could reduce oil and natural gas exploration and production activities and, therefore, adversely affect our business. Such laws or regulations could also materially increase our costs of compliance and doing business by more strictly regulating how hydraulic fracturing wastes are handled or disposed.
Endangered Species Act and Migratory Birds
The federal Endangered Species Act (“ESA”) and (in some cases) comparable state laws were established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. 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 sage grouse, that potentially could be listed as threatened or endangered under the ESA may exist. The U.S. Fish and Wildlife Service (the “FWS”) may designate critical habitat and suitable habitat areas that it believes are necessary for the survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit land access for oil and natural gas development. 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. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. Recently, there have been renewed calls to review protections currently in place for the dunes sagebrush lizard, whose habitat includes portions of the Permian Basin, and to reconsider listing the species under the ESA. The designation as threatened or endangered of previously unprotected species in areas where we operate could cause us to incur increased costs arising from species protection measures or could result in limitations on our development and production activities that could have a material adverse impact on our ability to develop and produce our 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.
OSHA
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.
Related Permits and Authorizations
Many environmental laws require us to obtain permits or other authorizations from state and/or federal agencies before initiating certain drilling, construction, production, operation, or other oil and natural gas activities and to maintain these permits and compliance with their requirements for on-going
operations. These permits are generally subject to protest, appeal, or litigation, which, in certain cases, can delay or halt projects and cease production or operation of wells, pipelines and other operations.
Related Insurance
We maintain insurance against some risks associated with above or underground contamination that may occur as a result of our exploration and production activities. However, this insurance is limited to activities at the well site, and there can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified against could have a material adverse effect on our financial condition and operations.
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.
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. 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 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. There is no assurance that we will be able to market all of the oil or gas produced by us or that favorable prices can be obtained for the oil and gas production.
We derive our revenue and cash flow principally from the sale of oil, natural gas and NGLs. As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil, natural gas and NGLs. We sell our oil and natural gas on the open market at prevailing market prices or through forward delivery contracts. Because some of our operations are located outside major markets, we are directly impacted by regional prices regardless of Henry Hub, WTI or other major market pricing. The market price for oil, natural gas and NGLs is dictated by supply and demand; consequently, we cannot accurately predict or control the price we may receive for our oil, natural gas and NGLs.
We have an active hedging program to mitigate risk regarding our cash flow and to protect returns from our development activity in the event of decreases in the prices received for our production; 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.
Major Customers
The Company sells its oil and gas production to a number of direct purchasers under direct contracts or through other operators under joint operating agreements. Listed below are the percent of the Company’s total oil and gas sales made which represented more than 10% of the Company’s oil and gas sales in the year 2021.
Oil Purchasers:
Apache Corporation
%
Plains All American Inc.
%
Gas Purchasers:
Apache Corporation
%
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.
Employees
At December 31, 2021, we had 113 full time employees, 31 of whom were employed at our principal offices in Houston, Texas, at the offices of Prime Operating Company, Eastern Oil Well Service Company and EOWS Midland Company, and 82 employees who were primarily involved in our district operations in Midland, Texas, Elmore City and Oklahoma City, Oklahoma.

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ITEM 1A. RISK FACTORS
Item 1A.
RISK FACTORS.
The prices of oil, NGL and gas are highly volatile and have declined significantly in recent years. A sustained decline in these commodity prices could materially and adversely affect the Company’s business, financial condition and results of operations.
Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for natural gas and oil. Lower commodity prices may reduce the amount of natural gas and oil that we can produce economically. Natural gas prices, based on the twelve-month average of the first of the month Henry Hub index price, were $3.598 per MMBTU in 2021 as compared to $1.985 per MMBTU in 2020, and have averaged $4.53 per MMBTU for the first three months of 2022. Oil prices, based on the NYMEX monthly average price, were $66.56 per barrel in 2021 as compared to $39.57 per barrel in 2020, and first of the Month NYMEX oil prices have averaged $88.94 per barrel for the first three months of 2022.
Any substantial or extended decline in future natural gas or crude oil prices would have a material adverse effect on our future business, financial condition, results of operations, cash flows, liquidity or ability to finance planned capital expenditures and commitments. Furthermore, substantial, extended decreases in natural gas and crude oil prices may cause us to delay or postpone a significant portion of our exploration, development and exploitation projects or may render such projects uneconomic, which may result in significant downward adjustments to our estimated proved reserves and could negatively impact our ability to borrow and cost of capital and our ability to access capital markets, increase our costs under our revolving credit facility, and limit our ability to execute aspects of our business plans.
Prices for natural gas and oil are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty and a variety of additional factors that are beyond our control. These factors include:
•
the level of consumer product demand;
•
weather conditions;
•
political conditions in natural gas and oil producing regions, including the Middle East, Africa and South America;
•
the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
•
the price levels and quantities of foreign imports;
•
actions of governmental authorities;
•
the availability, proximity and capacity of gathering, transportation, processing and/or refining facilities in regional or localized areas that may affect the realized price for natural gas and oil;
•
inventory storage levels;
•
the nature and extent of domestic and foreign governmental regulations and taxation, including environmental and climate change regulation;
•
the price, availability and acceptance of alternative fuels;
•
technological advances affecting energy consumption;
•
speculation by investors in oil and natural gas;
•
variations between product prices at sales points and applicable index prices;
•
overall economic conditions and
•
global or national health concerns, including the outbreak of pandemic or contagious disease, such as the coronavirus.
In response to recent volatility in commodity prices, many producers have reduced their capital expenditure budgets. If the prices of oil and natural gas decline further, our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves may be materially and adversely affected.
In addition, lower oil and natural gas prices may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our exploration or development activities are curtailed, full cost accounting rules may require us to write down, as a noncash charge to earnings, the carrying value of our oil and natural gas properties. Reductions in our reserves could also negatively impact the borrowing base under our revolving credit facility, which could further limit our liquidity and ability to conduct additional exploration and development activities.
Concerns over general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.
Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, the European, Asian and the United States financial markets have in the past contributed, and may in the future contribute, to economic uncertainty and diminished expectations for the global economy. In addition, continued hostilities in the Middle East, the occurrence or threat of terrorist attacks in the United States or other countries and global or national health concerns could adversely affect the global economy. These factors, combined with volatility in commodity prices, business and consumer confidence and unemployment rates, may precipitate an economic slowdown. Concerns about global economic growth may have an adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact our results of operations, liquidity and financial condition. These factors and the volatile nature of the energy markets make it impossible to predict with any certainty the future prices of natural
gas and oil. If natural gas and oil prices decline significantly for a sustained period of time, the lower prices may adversely affect our ability to make planned expenditures, raise additional capital or meet our financial obligations.
Financial difficulties encountered by our oil and natural gas purchasers, third-party operators or other third parties could decrease cash flow from operations and adversely affect our exploration and development activities.
We derive essentially all of our revenues from the sale of our oil, natural gas and NGLs to unaffiliated third-party purchasers, independent marketing companies and midstream companies. Any delays in payments from such purchasers caused by their financial difficulties, including those resulting from the impacts of COVID-19
and its impact on the global economy, will have an immediate negative effect on our results of operations and cash flows.
Additionally, liquidity and cash flow problems encountered by our working interest co-owners
or the third-party operators of our non-operated
properties may prevent or delay the drilling of a well or the development of a project. Our working interest co-owners
may be unwilling or unable to pay their share of the costs of projects as they become due. In the case of a working interest owner, we could be required to pay the working interest owner’s share of the project costs.
The shut-in
of our wells could negatively impact our production, liquidity, and, ultimately, our operations, results, and performance.
Our production depends, in part, upon our wells that are capable of commercial production not being shut-in
(i.e., suspended from production). The lack of availability of capacity on third-party systems and facilities or the shut-in
of an oil field’s production could result in the shut-in
of our wells. In response to recent commodity prices our efforts to reduce costs include reducing operating costs. The Company elected to shut-in
marginal wells and will continue to review field operations to minimize costs and identify wells for short term shut-ins
through May and June.
The producing wells in which we have an interest occasionally experience reduced or terminated production. These curtailments can result from mechanical failures, contract terms, pipeline and processing plant interruptions, market conditions, operator priorities, and weather conditions. These curtailments can last from a few days to many months, any of which could have an adverse effect on our results of operations.
If we experience low oil production volumes due to the shut-in
of our wells or other mechanical failures or interruptions, it would impact our ability to generate cash flows from operations and we could experience a reduction in our available liquidity. A decrease in our liquidity could adversely affect our ability to meet our anticipated working capital, debt service, and other liquidity needs.
Drilling natural gas and oil wells is a high-risk activity.
Our growth is materially dependent upon the success of our drilling program. Drilling for natural gas and oil involves numerous risks, including the risk that no commercially productive natural gas or oil reservoirs will be encountered. The cost of drilling, completing and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors beyond our control, including:
•
decreases in natural gas and oil prices;
•
unexpected drilling conditions, pressure or irregularities in formations;
•
equipment failures or accidents;
•
adverse weather conditions;
•
loss of title or other title related issues;
•
surface access restrictions;
•
lack of available gathering or processing facilities or delays in the construction thereof;
•
compliance with, or changes in, governmental requirements and regulation, including with respect to wastewater disposal, discharge of greenhouse gases and fracturing; and
•
shortages or delays in the availability of required goods or services such as drilling rigs or crews, the delivery of equipment and the availability of sufficient water for drilling operations.
Our future drilling activities may not be successful and, if unsuccessful, such failure will have an adverse effect on our future results of operations and financial condition. Our overall drilling success rate or our drilling success rate within a particular geographic area may decline. We may be unable to lease or drill identified or budgeted prospects within our expected time frame, or at all. We may be unable to lease or drill a particular prospect because, in some cases, we identify a prospect or drilling location before seeking an option or lease rights in the prospect or location. Similarly, our drilling schedule may vary from our capital budget. The final determination with respect to the drilling of any scheduled or budgeted wells will be dependent on a number of factors, including:
•
the results of exploration efforts and the acquisition, review and analysis of the seismic data;
•
the availability of sufficient capital resources to us and the other participants for the drilling of the prospects;
•
the approval of the prospects by other participants after additional data has been compiled;
•
economic and industry conditions at the time of drilling, including prevailing and anticipated prices for natural gas and oil and the availability of drilling rigs and crews;
•
our financial resources and results; and
•
the availability of leases and permits on reasonable terms for the prospects.
These projects may not be successfully developed and the wells, if drilled, may not encounter reservoirs of commercially productive natural gas or oil.
Reserve estimates depend on many assumptions that may prove to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated.
Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact manner. The process of estimating quantities of proved reserves is complex and inherently uncertain, and the reserve data included in this document are only estimates. The process relies on interpretations of available geologic, geophysical, engineering and production data. As a result, estimates of different engineers may vary. In addition, the extent, quality and reliability of this technical data can vary. The differences in the reserve estimation process are substantially due to the geological conditions in which the wells are drilled. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as natural gas and oil prices. Additional assumptions include drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserve estimate is a function of:
•
the quality and quantity of available data;
•
the interpretation of that data;
•
the accuracy of various mandated economic assumptions; and
•
the judgment of the persons preparing the estimate.
Results of drilling, testing and production subsequent to the date of an estimate may justify revising the original estimate. Accordingly, initial reserve estimates often vary from the quantities of natural gas and oil that are ultimately recovered, and such variances may be material. Any significant variance could reduce the estimated quantities and present value of our reserves.
You should not assume that the present value of future net cash flows from our proved reserves is the current market value of our estimated natural gas and oil reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on the twelve-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first day of the month price for each month, and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor we use when calculating discounted future net cash flows for reporting requirements in compliance with the Financial Accounting Standards Board (“FASB”) in Accounting Standards Codification (“ASC”) Section 932 may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.
The Company’s expectations for future drilling activities will be realized over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of such activities.
The Company has identified drilling locations and prospects for future drilling opportunities, including development and infill drilling activities. These drilling locations and prospects represent a significant part of the Company’s future drilling plans. The Company’s ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, negotiation of agreements with third parties, commodity prices, costs, access to and availability of equipment, services, resources and personnel and drilling results. Changes in the laws or regulations on which the Company relies in planning and executing its drilling programs could adversely impact the Company’s ability to successfully complete those programs. For example, under current Texas laws and regulations the Company may receive permits to drill, and may drill and complete, certain horizontal wells that traverse one or more units and/or leases; a change in those laws or regulations could adversely impact the Company’s ability to drill those wells. Because of these uncertainties, the Company cannot give any assurance as to the timing of these activities or that they will ultimately meet the Company’s expectations for success. As such, the Company’s actual drilling activities may materially differ from the Company’s current expectations, which could have a significant adverse effect on the Company’s proved reserves, financial condition and results of operations.
Our future performance depends on our ability to find or acquire additional natural gas and oil reserves that are economically recoverable.
In general, the production rate of natural gas and oil properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Unless we successfully replace the reserves that we produce, our reserves will decline, eventually resulting in a decrease in natural gas and oil production and lower revenues and cash flow from operations. Our future natural gas and oil production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves. We may not be able to replace reserves through our exploration, development and exploitation activities or by acquiring properties at acceptable costs. Low natural gas and oil prices may further limit the kinds of reserves that we can develop economically. Lower prices also decrease our cash flow and may cause us to decrease capital expenditures.
Exploration, development and exploitation activities involve numerous risks that may result in dry holes, the failure to produce natural gas and oil in commercial quantities and the inability to fully produce discovered reserves.
We are continually identifying and evaluating opportunities to acquire natural gas and oil properties. We may not be able to successfully consummate any acquisition, to acquire producing natural gas and oil properties that contain economically recoverable reserves, or to integrate the properties into our operations profitably.
We have substantial capital requirements, and we may not be able to obtain needed financing on satisfactory terms, if at all.
We rely upon access to our revolving credit facility as a source of liquidity for any capital requirements not satisfied by cash flow from operations or other sources. Future challenges in the global financial system, including the capital markets, may adversely affect our business and our financial condition. Our ability to access the capital markets may be restricted at a time when we desire, or need, to raise capital, which could have an impact on our flexibility to react to changing economic and business conditions. Adverse economic and market conditions could adversely affect the collectability of our trade receivables and cause our commodity hedging counterparties to be unable to perform their obligations or to seek bankruptcy protection. Future challenges in the economy could also lead to reduced demand for natural gas which could have a negative impact on our revenues.
Our debt agreements also require compliance with covenants to maintain specified financial ratios. If the price that we receive for our natural gas and oil production further deteriorates from current levels or continues for an extended period, it could lead to further reduced revenues, cash flow and earnings, which in turn could lead to a default under those ratios. Because the calculations of the financial ratios are made as of certain dates, the financial ratios can fluctuate significantly from period to period. A prolonged period of decreased natural gas and oil prices or a further decline could further increase the risk of our inability to comply with covenants to maintain specified financial ratios. In order to provide a margin of comfort with regard to these financial covenants, we may seek to reduce our capital expenditure plan, sell non-strategic
assets or opportunistically modify or increase our derivative instruments to the extent permitted under our debt agreements. In addition, we may seek to refinance or restructure all or a portion of our indebtedness. We cannot assure you that we will be able to successfully execute any of these strategies, and such strategies may be unavailable on favorable terms or not at all.
The borrowing base under our revolving credit facility may be reduced in light of recent commodity price declines, which could limit us in the future.
The borrowing base under our revolving credit facility is currently $50 million, and lender commitments under our revolving credit facility are $300 million. The borrowing base is redetermined semi-annually under the terms of the revolving credit facility. In addition, either we or the lenders may request an interim redetermination twice a year or in conjunction with certain acquisitions or sales of oil and gas properties. Our borrowing base may decrease as a result of lower natural gas or oil prices, operating difficulties, declines in reserves, lending requirements or regulations, the issuance of new indebtedness or for other reasons set forth in our revolving credit agreement. In the event of a decrease in our borrowing base due to declines in commodity prices or otherwise, our ability to borrow under our revolving credit facility may be limited and we could be required to repay any indebtedness in excess of the redetermined borrowing base. In addition, we may be unable to access the equity or debt capital markets to meet our obligations, including any such debt repayment obligations.
Strategic determinations, including the allocation of capital and other resources to strategic opportunities, are challenging, and our failure to appropriately allocate capital and resources among our strategic opportunities may adversely affect our financial condition and reduce our growth rate.
Our future growth prospects are dependent upon our ability to identify optimal strategies for our business. In developing our business plan, we considered allocating capital and other resources to various aspects of our businesses including well-development (primarily drilling), reserve acquisitions, exploratory activity, corporate items and other alternatives. We also considered our likely sources of capital. Notwithstanding the determinations made in the development of our 2022 plan, business opportunities not previously identified
periodically come to our attention, including possible acquisitions and dispositions. If we fail to identify optimal business strategies, or fail to optimize our capital investment and capital raising opportunities and the use of our other resources in furtherance of our business strategies, our financial condition and growth rate may be adversely affected. Moreover, economic or other circumstances may change from those contemplated by our 2021 plan, and our failure to recognize or respond to those changes may limit our ability to achieve our objectives.
Negative public perception regarding us and/or our industry could have an adverse effect on our operations.
Negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about hydraulic fracturing, oil spills, greenhouse gas or methane emissions and explosions of natural gas transmission lines, may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we need to conduct our operations to be withheld, delayed, or burdened by requirements that restrict our ability to profitably conduct our business.
We face a variety of hazards and risks that could cause substantial financial losses.
Our business involves a variety of operating risks, including:
•
blowouts, cratering and explosions;
•
mechanical problems;
•
uncontrolled flows of natural gas, oil or well fluids;
•
formations with abnormal pressures;
•
pollution and other environmental risks; and
•
natural disasters.
Our operation of natural gas gathering and pipeline systems also involves various risks, including the risk of explosions and environmental hazards caused by pipeline leaks and ruptures.
We may not be insured against all of the operating risks to which we are exposed.
We maintain insurance coverage against certain, but not all, hazards that could arise from our operations. Such insurance is believed to be reasonable for the hazards and risks faced by us. We do not carry business interruption insurance. In addition, pollution and environmental risks are not fully insurable.
We maintain for our operations total excess liability insurance with limits of $20 million per occurrence and in the aggregate covering certain general liability and certain “sudden and accidental” environmental risks with a deductible of $10,000 per occurrence, subject to all terms, restrictions and sub-limits
of the policies. We also maintain general liability insurance limits of $1 million per occurrence and $2 million in the aggregate.
We have several policies that cover environmental risks. We have environmental coverage under the per occurrence and aggregate limits of our general and umbrella liability policies (for a twelve-month term). These policies provide third-party surface cleanup, bodily injury and property damage coverage, and defense costs when a pollution event is sudden and accidental and is discovered within thirty days of commencement and reported to the insurance company within ninety days of discovery. This is standard coverage in oil and gas insurance policies.
We seek to protect ourselves from some but not all operating hazards through insurance coverage. However, some risks are either not insurable or insurance is available only at rates that we consider uneconomical. Depending on competitive conditions and other factors, we attempt to obtain contractual protection against uninsured operating risks from our customers and contractors. However, customers and contractors who provide contractual indemnification protection may not in all cases maintain adequate insurance to support their indemnification obligations. Our insurance or indemnification arrangements may not adequately protect us against liability or loss from all the hazards of our operations. The occurrence of a significant event that we have not fully insured or indemnified against or the failure of a customer to meet its indemnification obligations to us could materially and adversely affect our results of operations and financial condition. Furthermore, we may not be able to maintain adequate insurance in the future at rates we consider reasonable.
From time to time, a small number of our contractors have requested contractual provisions that require us to respond to third-party claims. In some of these instances we have accepted the risk with the understanding that it would be covered under our current coverage. We evaluate these risk-transferring negotiations cautiously, and we feel that we have adequately mitigated this risk through existing coverage or acquiring supplemental coverage when appropriate.
Laws and regulations regarding hydraulic fracturing, as well as governmental reviews of such activities, could result in increased costs and additional operating restrictions, delays or cancellations and have a material adverse effect on the Company’s production.
Hydraulic fracturing is a common practice that is used to stimulate production of hydrocarbons from tight formations. The Company conducts hydraulic fracturing in its drilling and completion programs. The process involves the injection of water, sand or other proppants and additives under pressure into targeted subsurface formations to stimulate oil and gas production. The process is typically regulated by state oil and gas commissions or similar agencies, but in recent years, several federal agencies have conducted investigations or asserted regulatory authority over certain aspects of the process. For example, in 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances. Additionally, the EPA has asserted regulatory authority pursuant to the SDWA’s UIC program over hydraulic fracturing activities involving the use of diesel and has issued guidance covering such activities. Moreover, the EPA has published an Advance Notice of Proposed Rulemaking to collect data on chemicals used in hydraulic fracturing under the Toxic Substances Control Act and has implemented a final rule under the CWA prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly-owned wastewater treatment plants. Also, the federal Bureau of Land Management (“BLM”) published a final rule in 2015 that established new or more stringent standards for performing hydraulic fracturing on federal and Indian lands. The BLM rescinded the 2015 rule in late 2017; however, litigation challenging the BLM’s decision to rescind the 2015 rule remains pending in federal district court.
From time to time, the U.S. Congress has considered adopting legislation intended to provide for federal regulation of hydraulic fracturing and to require disclosure of the additives used in the hydraulic-fracturing process. In addition, certain states, including Texas where the Company operates, have adopted, and other states are considering adopting, regulations that could impose new or more stringent permitting, disclosure, disposal and well-construction requirements on hydraulic-fracturing operations. For example, in April 2019, Colorado passed legislation reforming exploration and production activities by the oil and gas industry in the state including, among other things, revising the mission of the state oil and gas agency from fostering energy development in the state to instead focusing on regulating the industry in a manner that is protective of public health and safety and the environment, as well as authorizing cities and counties to regulate oil and gas operations within their jurisdictions as they do other development. While the Company does not conduct operations in Colorado, passage or enactment of similar legislation in other states in which it does operate could significantly increase the Company’s operating costs and have a significant adverse effect on the Company’s ability to conduct operations. States could elect to prohibit hydraulic fracturing or high volume hydraulic
fracturing altogether, following the approach taken by the states of Vermont, Maryland and New York. Also, local land use restrictions, such as city ordinances, may be adopted to restrict or prohibit drilling in general or hydraulic fracturing in particular. In Texas, legislation was adopted providing that the regulation of oil and gas operations in Texas is under the exclusive jurisdiction of the state and thus preempts local regulation of those operations. Nonetheless, municipalities and political subdivisions in Texas continue to have the right to enact “commercially reasonable” regulations for surface activities.
In the event federal, state or local restrictions or bans pertaining to hydraulic fracturing are adopted in areas where the Company is currently conducting operations, or in the future plans to conduct operations, the Company may incur additional costs to comply with such requirements, experience restrictions, delays or cancellations in the pursuit of exploration, development or production activities, and perhaps be limited or precluded in the drilling of wells or in the volume that the Company is ultimately able to produce from its reserves; one or more of which developments could have a material adverse effect on the Company.
The Company’s operations are subject to stringent environmental, oil and gas-related
and occupational safety and health laws and regulations that could cause it to delay, curtail or cease its operations or expose it to material costs and liabilities.
The Company’s operations are subject to stringent federal, state and local laws and regulations governing, among other things, the drilling of wells, rates of production, the size and shape of drilling and spacing units or proration units, the transportation and sale of oil, NGL and gas, and the discharging of materials into the environment and environmental protection. For example, state laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and gas properties. Some states allow forced pooling or integration of tracts to facilitate development, while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce the Company’s interest in the unitized properties. In addition, state conservation laws (i) establish maximum rates of production from oil and gas wells, (ii) generally prohibit the venting or flaring of gas and (iii) impose requirements regarding production rates. These laws and regulations may limit the amount of oil and gas the Company can produce from the Company’s wells or limit the number of wells or the locations that the Company can drill.
In connection with its operations, the Company must obtain and maintain numerous environmental and oil and gas-related
permits, approvals and certificates from various federal, state and local governmental authorities, and may incur substantial costs in doing so. The need to obtain permits has the potential to delay, curtail or cease the development of oil and gas projects. The Company may in the future be charged royalties on gas emissions or required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in 2015, the EPA issued a final rule under the CAA lowering the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone from 75 parts per billion to 70 parts per billion under standards to provide protection of public health and welfare. In subsequent years, the EPA has issued area designations with respect to ground-level ozone and final requirements that apply to state, local and tribal air agencies for implementing the 2015 NAAQS for ground-level ozone. State implementation of the revised NAAQS could, among other things, require installation of new emission controls on some of the Company’s equipment, resulting in longer permitting timelines, and significantly increase the Company’s capital expenditures and operating costs. In another example, the EPA and U.S. Army Corps of Engineers (the “Corps”) released a final rule in 2015 outlining federal jurisdictional reach under the CWA over waters of the U.S., including wetlands. In 2017, the EPA and the Corps agreed to reconsider the 2015 rule and, thereafter, on October 22, 2019, the agencies published a final rule, which became effective on December 31, 2019, rescinding the 2015 rule. On January 23, 2020, the two agencies issued a final rule re-defining
the Clean Water Act’s jurisdiction over waters of the United States, which redefinition is narrower than found in the 2015 rule. Upon being published in the Federal Register and the passage of 60 days thereafter, the January 23, 2020 final rule will become effective, at which point the United States will be covered under a single regulatory scheme as it relates to federal jurisdictional reach over waters of the United States. However, there remains the expectation that the
January 23, 2020 final rule also will be legally challenged in federal district court. To the extent that any challenge to the January 23, 2020 final rule is successful and the 2015 rule or a revised rule expands the scope of the Clean Water Act’s jurisdiction in areas where the Company conducts operations, the Company could incur (i) delays, restrictions or prohibitions in the issuance of necessary permits, (ii) restrictions or cessations in the development or expansion of projects, or (iii) increases in the Company’s capital expenditures and operating expenses by, for example, requiring installation of new emission controls on some of the Company’s equipment, any one or more of which developments could have a material adverse effect on the Company’s business, financial condition and results of operations.
Additionally, the Company’s operations are subject to a number of federal and state laws and regulations, including the federal OSHA and comparable state statutes, whose purpose is to protect the health and safety of employees. Among other things, the OSHA hazard communication standard, the EPA community right-to-know
regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in the Company’s operations and that this information be provided to employees, state and local government authorities and citizens.
There can be no assurance that existing or future regulations will not result in a delay, curtailment or cessation of production or processing activities, result in a material increase in the costs of production, development, exploration or processing operations or materially and adversely affect the Company’s future operations and financial condition. Noncompliance with these laws and regulations may subject the Company to sanctions, including administrative, civil or criminal penalties, remedial cleanups or corrective actions, delays in permitting or performance of projects, natural resource damages and other liabilities. Such laws and regulations may also affect the costs of acquisitions. In addition, these laws and regulations are subject to amendment or replacement in the future with more stringent legal requirements. Further, any delay, reduction or curtailment of the Company’s development and producing operations due to these laws and regulations could result in the loss of acreage through lease expiration.
The nature of the Company’s assets and production operations may impact the environment or cause environmental contamination, which could result in material liabilities to the Company.
The Company’s assets and production operations may give rise to significant environmental costs and liabilities as a result of the Company’s handling of petroleum hydrocarbons and wastes, because of air emissions and water discharges related to its operations, and due to past industry operations and waste disposal practices. The Company’s oil and gas business involves the generation, handling, treatment, storage, transport and disposal of wastes, hazardous substances and petroleum hydrocarbons and is subject to environmental hazards, such as oil and produced water spills, NGL and gas leaks, pipeline and vessel ruptures and unauthorized discharges of such wastes, substances and hydrocarbons, that could expose the Company to substantial liability due to pollution and other environmental damage. For example, drilling fluids, produced waters and certain other wastes associated with the Company’s exploration, development and production of oil or gas are currently excluded under RCRA from the definition of hazardous waste. These wastes are instead regulated under RCRA’s less stringent non-hazardous
waste provisions. There have been efforts from time to time to remove this exclusion. For example, in response to a federal consent decree issued in 2016, the EPA was required during 2019 to determine whether certain Subtitle D criteria regulations required revision in a manner that could result in oil and gas wastes being regulated as RCRA hazardous waste. In April 2019, the EPA made a determination that such revision of the regulations was unnecessary. Any future loss of the RCRA exclusion could have a material adverse effect on the Company’s results of operations and financial position.
The Company currently owns, leases or operates, and in the past has owned, leased or operated, properties that for many years have been used for oil and gas exploration and production activities, and petroleum hydrocarbons, hazardous substances and wastes may have been released on or under such properties, or on or under other locations, including off-site
locations, where such substances have been taken for treatment or
disposal. These wastes, substances and hydrocarbons may also be released during future operations. In addition, some of the Company’s properties have been operated by predecessors or previous owners or operators whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons were not under the Company’s control. Joint and several strict liabilities may be incurred in connection with such releases of petroleum hydrocarbons, hazardous substances and wastes on, under or from the Company’s properties. Private parties, including lessors of properties on which the Company operates and the owners or operators of properties adjacent to the Company’s operations and facilities where the Company’s petroleum hydrocarbons, hazardous substances or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as seek damages for noncompliance with environmental laws and regulations or for personal injury or damage to property or natural resources. Such properties and the substances disposed or released on or under them may be subject to CERCLA, RCRA and analogous state laws, which could require the Company to remove previously disposed substances, wastes and petroleum hydrocarbons, remediate contaminated property or perform remedial plugging or pit closure operations to prevent future contamination, the costs of which could have a material adverse effect on the Company’s business, financial condition and results of operations.
The Company may not be able to recover some or any of these costs from sources of contractual indemnity or insurance, as pollution and similar environmental risks generally are not insurable or fully insurable, either because such insurance is not available or because of the high premium costs and deductibles associated with obtaining such insurance.
The Company’s operations are subject to a number of risks arising out of concerns regarding the threat of climate change, including regulatory, political, litigation and financial risks, that could result in increased operating costs and costs of compliance, limit the areas in which oil and gas production may occur, reduce demand for the oil and gas the Company produces, and expose the Company to the risk of increased activism and decreased funding for the industry, while the potential physical effects of climate change could disrupt the Company’s production and cause it to incur significant costs in preparing for or responding to those effects.
The threat of climate change continues to attract considerable attention in the United States and in foreign countries. Numerous initiatives have been proposed and are expected to continue to be proposed at the international, national, regional and state levels of government to monitor and limit existing sources of GHG emissions as well as to restrict or eliminate emissions from new sources. As a result, the Company’s operations are subject to a series of regulatory, political, litigation and financial risks associated with the production and processing of fossil fuels and emission of GHGs.
In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among other things, (i) establish construction and operating permit reviews for GHG emissions from certain large stationary sources, (ii) require the monitoring and annual reporting of GHG emissions from certain petroleum and gas system sources in the United States, (iii) implement CAA emission standards directing the reduction of methane from certain new, modified, or reconstructed facilities in the oil and gas sector, and (iv) together with the DOT, implement GHG emissions limits on vehicles manufactured for operation in the United States. Additionally, various states, groups of states, and other countries have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, there is a non-binding
agreement, the United Nations sponsored “Paris Agreement,” for nations to limit their GHG emissions through individually-determined reduction goals every five years after 2020, although the United States has announced its withdrawal from such agreement, effective November 4, 2020.
Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate change related pledges made by
certain candidates seeking the office of the President of the United States in 2020. Critical declarations made by one or more candidates running for President include proposals to ban hydraulic fracturing of oil and gas wells and ban new leases for production of minerals on federal properties, including onshore lands and offshore waters. Other actions that could be pursued by presidential candidates may include more restrictive requirements for the establishment of pipeline infrastructure or the permitting of LNG export facilities, the reversal of the United States’ withdrawal from the Paris Agreement in November 2020 and reinstatement of the ban on oil exports. Litigation risks are also increasing, as a number of cities, local governments or other persons have sought to bring suit against oil and gas exploration and production companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those impacts.
There are also financial risks for fossil fuel producers as stockholders or bondholders currently invested in fossil-fuel energy companies concerned about the threat of climate change may elect in the future to shift some or all of their investments into non-fossil
fuel energy related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. Additionally, investing and lending practices of various investment firms and institutional lenders have been the subject of intensive lobbying efforts in recent years, oftentimes public in nature, by environmental activists, proponents of the Paris Agreement, and foreign citizenry concerned about the threat of climate change not to provide funding for fossil fuel producers. For example, there have been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds, to divest of fossil fuel equities and lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities.
The adoption and implementation of new or more stringent international, federal or state regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from the oil and gas sector or otherwise restrict the areas in which this sector may produce oil and gas or generate GHG emissions could result in increased compliance and consumption costs, and thereby reduce demand for the oil and gas the Company produces. Additionally, political, litigation and financial risks could result in the restriction or cancellation of production activities, incurring liability for infrastructure damages as a result of climate changes, or impairing the Company’s ability to continue to operate in an economic manner. Finally, if increasing concentrations of GHGs in the Earth’s atmosphere were to result in significant physical effects, such as increased frequency and severity of storms, floods, droughts and other extreme climatic events, then such effects could have a material adverse effect on the Company’s exploration and production operations.
In addition, companies in the oil and gas industry have been the target of activist efforts from both individuals and non-governmental
organizations, including instituting litigation and supporting political or regulatory efforts to, among other things, limit or ban hydraulic fracturing, restrict or ban certain operating practices, including the disposal of waste materials, such as hydraulic fracturing fluids and produced water, deny or delay drilling permits, prohibit the venting or flaring of gas, reduce access of the oil and gas industry to federal and state government lands, and delay or cancel oil and gas developmental or expansion projects. The Company may need to incur significant costs associated with responding to these initiatives, and complying with any resulting additional legal or regulatory requirements could have a material adverse effect on the Company’s business, financial condition, cash flows and results of operations.
Laws and regulations pertaining to protection of threatened and endangered species or to critical habitat, wetlands and natural resources could delay, restrict or prohibit the Company’s operations and cause it to incur substantial costs that may have a material adverse effect on the Company’s development and production of reserves.
The federal ESA and comparable state laws were established to protect endangered and threatened species. Under the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Federal Migratory Bird Treaty Act. Oil and gas operations in the Company’s operating areas may be adversely affected by seasonal or permanent restrictions imposed on drilling activities by the U.S. Fish and Wildlife Services (the “FWS”) that are designed to protect various wildlife, which may materially restrict the Company’s access to federal or private land use. Permanent restrictions imposed to protect endangered and threatened species could prohibit drilling in certain areas, impact suppliers of critical materials or services, or require the implementation of expensive mitigation measures. Additionally, federal statutes, including the CWA, the OPA and CERCLA, as well as comparable state laws, prohibit certain actions that adversely affect critical habitat, wetlands and natural resources. If harm to species or damages to wetlands, habitat or natural resources occur or may occur, government entities or, at times, private parties may act to prevent oil and gas exploration or development activities or seek damages for harm to species, habitat or natural resources resulting from drilling, construction or releases of petroleum hydrocarbons, wastes, hazardous substances or other regulated materials, and, in some cases, may seek criminal penalties.
Moreover, as a result of one or more settlements entered into by the FWS, the agency is required to make determinations on the potential listing of numerous species as endangered or threatened under the ESA. The designation of previously unprotected species as threatened or endangered in areas where the Company conducts operations could cause the Company to incur increased costs arising from species protection measures or could result in delays, restrictions or prohibitions on its development and production activities that could have a material adverse effect on the Company’s ability to develop and produce reserves.
We have limited control over the activities on properties we do not operate.
Other companies operate some of the properties in which we have an interest. We have limited ability to influence or control the operation or future development of these non-operated
properties or the amount of capital expenditures that we are required to fund with respect to them. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interest could reduce our production and revenues. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.
Terrorist activities and the potential for military and other actions could adversely affect our business.
The threat of terrorism and the impact of military and other action have caused instability in world financial markets and could lead to increased volatility in prices for natural gas and oil, all of which could adversely affect the markets for our operations. Future acts of terrorism could be directed against companies operating in the United States. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of terrorist organizations. These developments have subjected our operations to increased risk and, depending on their ultimate magnitude, could have a material adverse effect on our business.
Our ability to sell our natural gas and oil production could be materially harmed if we fail to obtain adequate services such as transportation and processing.
The sale of our natural gas and oil production depends on a number of factors beyond our control, including the availability and capacity of transportation and processing facilities. Our failure to obtain these services on acceptable terms could materially harm our business.
Competition in our industry is intense, and many of our competitors have substantially greater financial and technological resources than we do, which could adversely affect our competitive position.
Competition in the natural gas and oil industry is intense. Major and independent natural gas and oil companies actively bid for desirable natural gas and oil properties, as well as for the equipment and labor required to operate and develop these properties. Our competitive position is affected by price, contract terms and quality of service, including pipeline connection times, distribution efficiencies and reliable delivery record. Many of our competitors have financial and technological resources and exploration and development budgets that are substantially greater than ours. These companies may be able to pay more for exploratory projects and productive natural gas and oil properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may be able to expend greater resources on the existing and changing technologies that we believe are and will be increasingly important to attaining success in the industry.
We may have hedging arrangements that expose us to risk of financial loss and limit the benefit to us of increases in prices for natural gas and oil.
From time to time, when we believe that market conditions are favorable, we use certain derivative financial instruments to manage price risks associated with our production in all of our regions. These hedging arrangements limit the benefit to us of increases in prices. While there are many different types of derivatives available, we generally utilize put options and swap agreements to attempt to manage price risk more effectively.
The put options used to establish floor prices for a fixed volume of production during a certain time period. They provide for payments from the counterparties if the index price falls below the floor. The swap agreements call for payments to, or receipts from, counterparties based on whether the index price for the period is greater or less than the fixed price established for that period when the swap is put in place. These arrangements limit the benefit to us of increases in prices. In addition, these arrangements expose us to risks of financial loss in a variety of circumstances, including when:
•
a counterparty is unable to satisfy its obligations
•
production is less than expected; or
•
there is an adverse change in the expected differential between the underlying price in the derivative instrument and actual prices received for our production.
The CFTC has promulgated regulations to implement statutory requirements for swap transactions. These regulations are intended to implement a regulated market in which most swaps are executed on registered exchanges or swap execution facilities and cleared through central counterparties. While we believe that our use of swap transactions exempt us from certain regulatory requirements, the changes to the swap market due to increased regulation could significantly increase the cost of entering into new swaps or maintaining existing swaps, materially alter the terms of new or existing swap transactions and/or reduce the availability of new or existing swaps. If we reduce our use of swaps as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable.
The loss of key personnel could adversely affect our ability to operate.
Our operations are dependent upon a relatively small group of key management and technical personnel, and one or more of these individuals could leave our employment. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on us. In addition, our drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers and other professionals. Competition for experienced geologists, engineers and some other professionals is intense. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be harmed.
We are subject to complex laws and regulations, including environmental regulations, which can adversely affect the cost, manner or feasibility of doing business.
Our operations are subject to extensive federal, state and local laws and regulations, including tax laws and regulations and those relating to the generation, storage, handling, emission, transportation and discharge of materials into the environment. These laws and regulations can adversely affect the cost, manner or feasibility of doing business. Many laws and regulations require permits for the operation of various facilities, and these permits are subject to revocation, modification and renewal. Governmental authorities have the power to enforce compliance with their regulations, and violations could subject us to fines, injunctions or both. These laws and regulations have increased the costs of planning, designing, drilling, installing and operating natural gas and oil facilities. In addition, we may be liable for environmental damages caused by previous owners of property we purchase or lease. Risks of substantial costs and liabilities related to environmental compliance issues are inherent in natural gas and oil operations. It is possible that other developments, such as stricter environmental laws and regulations, and claims for damages to property or persons resulting from natural gas and oil production, would result in substantial costs and liabilities.
A failure of technology systems, data breach or cyberattack could materially affect our operations
.
Our information technology systems may be vulnerable to security breaches, including those involving cyberattacks using viruses, worms or other destructive software, process breakdowns, phishing or other malicious activities, or any combination of the foregoing. Such breaches could result in unauthorized access to information, including customer, employee, or other confidential data. We do not carry insurance against these risks, although we do invest in security technology, perform penetration tests, and design our business processes to attempt to mitigate the risk of such breaches. However, there can be no assurance that security breaches will not occur. Moreover, the development and maintenance of these measures requires continuous monitoring as technologies change and security measures evolve. We have experienced, and expect to continue to experience, cyber security threats and incidents, none of which has been material to us to date. However, a successful breach or attack could have a material negative impact on our operations or business reputation and subject us to consequences such as litigation and direct costs associated with incident response.
Information technology solution failures, network disruptions, breaches of data security and cyberattacks could disrupt our operations by causing delays, impeding processing of transactions and reporting financial results, resulting in the unintentional disclosure of customer, employee or our information, or damage to our reputation. A system failure, data security breach or cyberattack could have a material adverse effect on our financial condition, results of operations or cash flows. In the past, we have experienced data security breaches resulting from unauthorized access to our e-mail
systems, which to date have not had a material impact on our business; however, there is no assurance that such impacts will not be material in the future.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B.
UNRESOLVED STAFF COMMENTS.
We are a smaller reporting company and therefore no response is required pursuant to this Item.

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ITEM 2. PROPERTIES
Item 2.
PROPERTIES.
Our executive offices, as well as offices of Prime Operating Company, Eastern Oil Well Service Company and EOWS Midland Company are located in leased premises in Houston, Texas.
We maintain district offices in Midland, Texas and Oklahoma City, Oklahoma and have field offices in Carrizo Springs and Midland, Texas, as well as, Elmore City, Oklahoma.
Substantially all of our oil and gas properties are subject to a mortgage given to collateralize indebtedness or are subject to being mortgaged upon request by our lenders for additional collateral.
The information set forth below concerning our properties, activities, and oil and gas reserves includes our interests in affiliated entities.
The following table sets forth the exploratory and development drilling experience with respect to wells in which we participated during the three years ended December 31, 2021. In 2021, we participated in the completion of twelve horizontal wells.
Gross
Net
Gross
Net
Gross
Net
Exploratory:
Oil
-
-
-
-
-
-
Gas
-
-
-
-
-
-
Dry
-
-
-
-
-
-
Development:
Oil
4.61
0.1
1.6
Gas
-
-
-
-
-
-
Dry
-
-
-
-
-
-
Total:
Oil
4.61
0.1
1.6
Gas
-
-
-
-
-
-
Dry
-
-
-
-
-
-
4.61
0.1
1.6
Oil and Gas Production
As of December 31, 2021, we had ownership interest in the following number of gross and net producing oil and gas wells (1)
.
Gross
Net
Producing wells(1)
:
Oil Wells
Gas Wells
(1)
A gross well is a well in which a working interest is owned. A net well is the sum of the fractional revenue interests owned in gross wells. Wells are classified by their primary product. Some wells produce both oil and gas.
The following table shows our net production of oil, NGL and natural gas for each of the three years ended December 31, 2021. “Net” production is net after royalty interests of others are deducted and is determined by multiplying the gross production volume of properties in which we have an interest by the percentage of the leasehold, mineral or royalty interest owned by us.
Oil (barrels)
738,000
726,996
1,242,000
NGL (barrels)
416,000
435,260
574,000
Gas (Mcf)
3,236,000
3,374,397
4,397,000
The following table sets forth our average sales prices together with our average production costs per unit of production for the three years ended December 31, 2021.
Average sales price per barrel of oil
$ 68.39
$ 38.02
$ 55.04
Average sales price per barrel of NGL
$ 26.97
$ 11.22
$ 15.87
Average sales price per Mcf of natural gas
$ 3.53
$ 1.24
$ 1.49
Average production costs per net equivalent barrel of oil(1)
$ 13.76
$ 12.25
$ 11.52
(1)
Net equivalent barrels are computed at a rate of 6 Mcf per barrel and costs exclude production taxes.
Average oil, NGL and gas prices received including the impact of derivatives were:
Average sales price per barrel of oil
$ 64.04
$ 45.79
$ 53.58
Average sales price per barrel of NGL
$ 26.97
$ 11.22
$ 16.49
Average sales price per Mcf of natural gas
$ 2.97
$ 1.38
$ 1.51
Acreage
The following table sets forth the approximate gross and net undeveloped acreage in which we have leasehold and mineral interests as of December 31, 2021. “Undeveloped acreage” is that acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether or not such acreage contains proved reserves.
Developed
Undeveloped
Total
Gross
Net
Gross
Net
Gross
Net
Leasehold acreage
90,933
25,358
-
-
90,933
25,358
Mineral fee acreage
1,640
19,257
20,897
Total
92,573
25,475
19,257
111,830
25,892
Total Net Undeveloped Acreage Expiration
In the event that production is not established, or we take no action to extend or renew the terms of our leases, our net undeveloped acreage that will expire over the next three years, as of December 31, 2021, is zero acres for the year ending December 31, 2022, zero in 2023, and zero acres in 2024.
Reserves
Our interests in proved developed and undeveloped oil and gas properties, including the interests held by the Partnerships, have been evaluated by Ryder Scott Company, L.P. for each of the three years ended December 31, 2021. The professional qualifications of the technical persons primarily responsible for overseeing the preparation of the reserve estimates can be found in Exhibit 99.1, the Ryder Scott Company, L.P. Report on Registrant’s Reserves Estimates. In matters related to the preparation of our reserve estimates, our district managers report to the Engineering Data manager, who maintains oversight and compliance responsibility for the internal reserve estimate process and provides oversight for the annual preparation of reserve estimates of 100% of our year-end
reserves by our independent third-party engineers, Ryder Scott Company, L.P. The members of our district and central groups consist of degreed engineers and geologists with between approximately twenty and thirty-five years of industry experience, and between eight and twenty-five years of experience managing our reserves. Our Engineering Data manager, the technical person primarily responsible for overseeing the
preparation of reserves estimates, has over thirty years of experience, holds a Bachelor degree in Geology and an MBA in finance and is a member of the Society of Petroleum Engineers and American Association of Petroleum Geologist. See Part II, Item 8 “Financial Statements and Supplementary Data”, for additional discussions regarding proved reserves and their related cash flows. All of our reserves are located within the continental United States. The following table summarizes our oil and gas reserves at each of the respective dates:
Reserve Category
Proved Developed
Proved Undeveloped
Total
As of
December 31,
Oil
(MBbls)
NGLs
(MBbls)
Gas
(MMcf)
Total
(MBoe)
Oil
(MBbls)
NGLs
(MBbls)
Gas
(MMcf)
Total
(MBoe)
Oil
(MBbls)
NGLs
(MBbls)
Gas
(MMcf)
Total
(MBoe)
4,381
2,914
19,995
10,268
1,833
1,017
4,547
3,608
6,214
3,931
24,542
14,235
2,684
2,258
13,633
7,214
1,784
3,897
3,221
4,468
3,045
17,530
10,435
5,386
2,882
23,902
12,252
-
-
-
-
5,386
2,882
23,902
12,252
(a) In computing total reserves on a barrels of oil equivalent (Boe) basis, gas is converted to oil based on its relative energy content at the rate of six Mcf of gas to one barrel of oil and NGLs are converted based upon volume; one barrel of natural gas liquids equals one barrel of oil.
In 2019, in West Texas, we participated in the initial three shallow horizontals on our Kashmir tract with one of each of these wells completed in the Wolfcamp “A”, Jo Mill, and Lower Spraberry. The Company has 48% interest in two of these wells and 5.3% in one well. All three wells were brought on production in May of 2019.
In 2020, in West Texas we participated in the drilling of seven wells: one for 8.6% interest which was brought into production in July of 2020, and six wells with an average 47.5% interest that were drilled but not completed at year-end
and therefore classified as Proved Undeveloped in the year-end
reserve report. The Company invested approximately $8.0 million in these seven wells in 2020. Also in 2020, reserves were added in West Texas through the addition of 11 horizontal wells completed in Midland County, Texas, in which we receive 0.56% to 1% over-riding royalty interest.
In 2021, in West Texas, we participated with Apache in the drilling of three additional horizontals on the Kashmir Tract in Upton County, Texas and completed these three wells in September of 2021 along with six other wells drilled in 2020 on the same lease that were drilled but uncompleted at year-end.
The Company has an average of 47.8% interest in these nine wells and invested approximately $30 million in these horizontal wells.
In our Oklahoma, Scoop-Stack play, in 2019, we participated in the drilling and completion of six wells on our WM Wallace tract for 7.67% interest, and nine wells, included on Slash, Osborn, and Leon tracts, with an average 1.34% interest. In addition, three wells drilled in Oklahoma in 2018, designated as proved undeveloped at year-end
2018, were completed in 2019 converting 24 Mboe of reserves to proved developed. Also in Oklahoma, six wells designated as Shut-in
on December 31, 2018, were brought into production in 2019: five located on our Ruthie tract, and one on our Braum tract.
In 2019, in our Gulf Coast region, we added production through the recompletion of three vertical wells in Polk County, Texas: one operated by the Company in which we have 72.5% interest, and two operated by Unit Petroleum in which the Company owns 2.81% working interest and 3.77% net revenue interest. In 2020, the Company successfully recompleted one additional operated well in the Segno field with a 72.5% interest.
At December 31, 2020, in total, the Company had 3,221 Mboe of proved undeveloped reserves attributable to 13 wells operated by others, 10 of which were drilled but not completed by year-end
2020, and three that were not drilled until 2021. The three new horizontals along with the six uncompleted wells at year-end
were brought online in late September and early October of 2021. These successful new wells are on our Kashmir tract in Upton County, Texas operated by Apache Corporation where. These nine PUD wells at year-end
2020 accounted for 3,127 Mboe of the total undeveloped reserves where the Company has an average 47.5% interest and invested
approximately $30 million dollars in these wells. The four other PUD wells, drilled but not completed at year-end
2020, are located in Grady County, Oklahoma and accounted for 95 Mboe of the total undeveloped reserves.
At December 31, 2021, the Company had 159 Mboe of proved developed shut-in
reserves attributable to three horizontals drilled and completed in Canadian County, Oklahoma in December of 2021, but not yet online. Reserves of the four PUD wells in Grady County, Oklahoma were not included in the 2021 year-end
reserve report as the operator does not have near-term plans for their completion. In the first quarter of 2022, the Company is participating in the drilling of four wells with SEM Operating Company for 10% interest and has received drilling proposals for an additional 17 horizontal wells to be drilled this year. In total the Company is likely to invest approximately $54 million in these 21 wells. Additional drilling and future development plans will be established based on an expectation of available cash flows from operations and availability of funds under our revolving credit facility.
We employ technologies to establish proved reserves that have been demonstrated to provide consistent results capable of repetition. The technologies and economic data being used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, geologic maps, production data, and well test data. The estimated reserves of wells with sufficient production history are estimated using appropriate decline curves. Estimated reserves of producing wells with limited production history and for undeveloped locations are estimated using performance data from analogous wells in the area. These wells are considered analogous based on production performance from the same formation and with similar completion techniques.
The estimated future net revenue (using current prices and costs as of those dates) and the present value of future net revenue (at a 10% discount for estimated timing of cash flow) for our proved developed and proved undeveloped oil and gas reserves at the end of each of the three years ended December 31, 2021, are summarized as follows (in thousands of dollars):
Proved Developed
Proved Undeveloped
Total
As of December 31,
Future Net
Revenue
Present
Value 10
Of Future
Net
Revenue
Future Net
Revenue
Present
Value 10
Of Future
Net
Revenue
Future Net
Revenue
Present
Value 10
Of Future
Net
Revenue
Present
Value 10
Of Future
Income
Taxes
Standardized
Measure of
Discounted
Cash flow
$ 116,592
$ 82,155
$ 42,700
$ 17,876
$ 159,292
$ 100,031
$ 18,419
$ 81,612
$ 43,886
$ 34,717
$ 37,346
$ 21,823
$ 81,232
$ 56,539
$ 14,920
$ 41,619
$ 275,227
$ 171,906
$ -
$ -
$ 275,227
$ 171,906
$ 36,100
$ 135,806
The PV 10 Value represents the discounted future net cash flows attributable to our proved oil and gas reserves before income tax, discounted at 10%. Although this measure is not in accordance with U.S. generally accepted accounting principles (“GAAP”), we believe that the presentation of the PV10 Value is relevant and useful to investors because it presents the discounted future net cash flow attributable to proved reserves prior to taking into account corporate future income taxes and the current tax structure. We use this measure when assessing the potential return on investment related to oil and gas properties. The PV10 of future income taxes represents the sole reconciling item between this non-GAAP
PV10 Value versus the GAAP measure presented in the standardized measure of discounted cash flow. A reconciliation of these values is presented in the last three columns of the table above. The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to proved oil and natural gas reserves after income tax, discounted at 10%.
“Proved developed” oil and gas reserves are reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. “Proved undeveloped” oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Our reserves include amounts attributable to non-controlling
interests in the Partnerships. These interests represent less than 10% of our reserves.
In accordance with U.S. generally accepted accounting principles, product prices are determined using the twelve-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first day of the month price for each month, adjusted for oilfield or gas gathering hub and wellhead price differentials (e.g. grade, transportation, gravity, sulfur, and basic sediment and water) as appropriate. Also, in accordance with SEC specifications and U.S. generally accepted accounting principles, changes in market prices subsequent to December 31 are not considered.
While it may be reasonably anticipated that the prices received for the sale of our production may be higher or lower than the prices used in this evaluation, as described above, and the operating costs relating to such production may also increase or decrease from existing levels, such possible changes in prices and costs were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation for the SEC case. Actual volumes produced, prices received and costs incurred may vary significantly from the SEC case.
Natural gas prices, based on the twelve-month average of the first of the month Henry Hub index price, were $3.598 per MMBtu in 2021 as compared to $1.985 per MMBtu in 2020, and $2.581 per MMBtu in 2019. Oil prices, based on the NYMEX first of the month average price, were $66.56 per barrel in 2021 as compared to $39.57 per barrel in 2020, and $55.69 per barrel in 2019. Since January 1, 2021, we have not filed any estimates of our oil and gas reserves with, nor were any such estimates included in any reports to, any federal authority or agency, other than the Securities and Exchange Commission.
District Information
The following table represents certain reserves and well information as of December 31, 2021.
Gulf
Coast
Mid-
Continent
West
Texas
Other
Total
Proved Reserves as of December 31, 2021 (MBoe)
Developed
2,383
8,957
12,252
Undeveloped
-
-
-
-
-
Total
2,383
8,957
12,252
Average Net Daily Production (Boe per day)
2,878
3,964
Gross Productive Wells (Working Interest and ORRI Wells)
1,532
Gross Productive Wells (Working Interest Only)
1,207
Net Productive Wells (Working Interest Only)
Gross Operated Productive Wells
-
Gross Operated Water Disposal, Injection and Supply wells
-
In several of our producing regions we have field service groups to service our operated wells and locations as well as third-party operators in the area. These services consist of well service support, site preparation and construction services for drilling and workover operations. Our operations are performed utilizing workover or swab rigs, water transport trucks, saltwater disposal facilities, various land excavating equipment and trucks we own and that are operated by our field employees.
Gulf Coast Region
Our development, exploitation, exploration and production activities in the Gulf Coast region are primarily concentrated in southeast Texas. This region is managed from our office in Houston, Texas. Principal producing intervals are in the Wilcox, San Miguel, Olmos, and Yegua formations at depths ranging from 3,000 to 12,500 feet. We had 207 producing wells (105 net) in the Gulf Coast region as of December 31, 2021, of which 137 wells are operated by us. Average net daily production in our Gulf Coast Region in 2021 was 336 Boe. At December 31, 2021, we had 906 MBoe of proved reserves in the Gulf Coast region, which represented 7% of our total proved reserves. We maintain an acreage position of over 11,500 gross (3,967 net) acres in this region,
primarily in Dimmit and Polk counties. We operate a field service group in this region from a field office in Carrizo Springs, Texas utilizing four workover rigs, nineteen water transport trucks, two saltwater disposal wells and several trucks and excavating equipment. Services including well service support, site preparation and construction services for drilling and workover operations are provided to third-party operators as well as utilized in our own operated wells and locations. As of March 31, 2022, the Gulf Coast region has no operated wells in the process of being drilled, no waterfloods in the process of being installed and no other related activities of material importance.
Mid-Continent
Region
Our Mid-Continent
activities are concentrated in central Oklahoma. This region is managed from our office in Oklahoma City, Oklahoma. As of December 31, 2021, we had 549 producing wells (189 net) in the Mid-Continent
area, of which 195 wells are operated by us. Principal producing intervals are in the Roberson, Avant, Skinner, Sycamore, Bromide, McLish, Hunton, Mississippian, Oswego, Red Fork, and Chester formations at depths ranging from 1,100 to 10,500 feet. Average net daily production in our Mid-Continent
Region in 2021 was 747 Boe. At December 31, 2021, we had 2,383 MBoe of proved reserves in the Mid-Continent
area, representing 20% of our total proved reserves. We maintain an acreage position of approximately 48,400 gross (10,802 net) acres in this region, primarily in Canadian, Kingfisher, Grant, Major, and Garvin counties. Our Mid-Continent
region is actively participating with third-party operators in the horizontal development of lands that include Company owned interest in several counties in the Stack and Scoop plays of Oklahoma where drilling is primarily targeting reservoirs of the Mississippian, and Woodford formations.
As of March 31, 2022, in the Mid-Continent
region, the Company has agreed to participate with 9.38% interest in the drilling of four horizontal wells in Canadian County, Oklahoma operated by Ovintiv Mid-Continent
Inc. The first of these is slated to begin drilling in early April and completion of all four wells is expected in June of this year. These proved undeveloped drilling plans and their reserves were not included in the 2021 year-end
reserve report.
West Texas Region
Our West Texas activities are concentrated in the Permian Basin in Texas and New Mexico. The Spraberry field was discovered in 1949, encompasses eight counties in West Texas and the Company believes it is the largest oil field in the United States. The field is approximately 150 miles long and 75 miles wide at its widest point. The oil produced is West Texas Intermediate Sweet, and the gas produced is casing-head gas with an average energy content of 1,400 Btu. The oil and gas are produced primarily from five intervals; the Upper and Lower Spraberry, the Wolfcamp, the Strawn, and the Atoka, at depths ranging from 6,700 feet to 11,300 feet. This region is managed from our office in Midland, Texas. As of December 31, 2021, we had 576 wells (263 net) in the West Texas area, of which 321 wells are operated by us. Principal producing intervals are in the Spraberry, Wolfcamp, and San Andres formations at depths ranging from 4,200 to 12,500 feet. Average net daily production in Our West Texas Region in 2021 was 2,878 Boe. At December 31, 2021, we had 8,957 MBoe of proved reserves in the West Texas area, or 73% of our total proved reserves. We maintain an acreage position of approximately 17,148 gross (10,639 net) acres in the Permian Basin in West Texas, primarily in Reagan, Upton, Martin and Midland counties and believe this acreage has significant resource potential for horizontal drilling in the Spraberry, Jo Mill, and Wolfcamp intervals. We operate a field service group in this region utilizing nine workover rigs, four hot oiler trucks, one kill truck and two roustabout trucks. Services, including well service support, site preparation and construction services for drilling and workover operations, are provided to third-party operators as well as utilized in our own operated wells and locations.
As of March 31, 2022, the Company was participating with 10.3% interest in the drilling of four horizontal wells in Irion County, Texas operated by SEM Operating Company, LLC. These four wells are expected to be completed in the second quarter of 2022. In addition, the Company has received proposals for 13 new horizontal wells in West Texas and intends to participate for 50% interest in the drilling of nine horizontal wells in Reagan
County, Texas with BTA Oil Producers, Inc and to participate for 38% in the drilling of four horizontal wells in Martin County, Texas with Conoco Inc. These 13 wells are planned to be drilled in the third quarter of 2022. These proved undeveloped drilling plans have been added in the first quarter of 2022 and were not included in the year-end
2021 reserves report.

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ITEM 3. LEGAL PROCEEDINGS
Item 3.
LEGAL PROCEEDINGS.
None.

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ITEM 4. MINE SAFETY DISCLOSURE
Item 4.
MINE SAFETY DISCLOSURES.
Not applicable.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
Item 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
Our common stock is listed and principally traded on the NASDAQ Stock Market under the ticker symbol “PNRG”. The following table presents the high and low prices per share of our common stock during certain periods, as reported in the consolidated transaction reporting system.
High
Low
First Quarter
$ 98.00
$ 34.33
Second Quarter
53.72
39.89
Third Quarter
73.80
45.20
Fourth Quarter
71.71
58.50
First Quarter
$ 154.38
$ 47.68
Second Quarter
110.79
49.70
Third Quarter
79.13
62.60
Fourth Quarter
71.80
42.39
The above quotations reflect inter-dealer prices, without retail mark-up,
mark-down or commissions, and may not represent actual transactions.
As of April 20, 2022, there were 224 registered holders of the common stock.
Provisions of our line of credit agreement restrict our ability to pay dividends. Such dividends may be declared out of funds legally available therefore, when and as declared by our Board of Directors.
`Issuer Purchases of Equity Securities
In December 1993, we announced that the Board of Directors authorized a stock repurchase program whereby we may purchase outstanding shares of the common stock from time-to-time,
in open market transactions or negotiated sales. On October 31, 2012 and June 13, 2018, the Board of Directors of the Company approved an additional 500,000 and 200,000 respectively, shares of the Company’s stock to be included in the stock repurchase program. A total of 3,700,000 shares have been authorized, to date, under this program. Through December 31, 2021, a total of 3,554,379 shares have been repurchased under this program for $75,079,717 at an average price of $21.12 per share. Additional purchases of shares may occur as market conditions warrant. We expect future purchases will be funded with internally generated cash flow or from working capital.
2021 Month
Number of
Shares
Average Price Paid
per share
Maximum Number of
Shares that May Yet
Be Purchased Under
The Program at
Month-End
January
-
$ -
147,721
February
-
-
147,721
March
-
-
147,721
April
-
-
147,721
May
-
-
147,721
June
-
-
147,721
July
-
-
147,721
2021 Month
Number of
Shares
Average Price Paid
per share
Maximum Number of
Shares that May Yet
Be Purchased Under
The Program at
Month-End
August
-
-
147,721
September
-
-
147,721
October
-
-
147,721
November
-
-
147,721
December
2,100
69.04
145,621
Total / Average
2,100
$ 69.04

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ITEM 6. SELECTED FINANCIAL DATA
Item 6.
SELECTED FINANCIAL DATA
We are a smaller reporting company and therefore no response is required pursuant to this Item.

---

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
Item 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion is intended to assist you in understanding our results of operations and our present financial condition. Our Consolidated Financial Statements and the accompanying Notes to the Consolidated Financial Statements included elsewhere in this Report contains additional information that should be referred to when reviewing this material. Our subsidiaries are listed in Note 1 to the Consolidated Financial Statements.
Overview:
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. In addition, we own a substantial amount of well servicing equipment. All of our oil and gas properties and interests are located in the United States. Assets in our principal focus areas include mature properties with long-lived reserves and significant development opportunities as well as newer properties with development and exploration potential. We believe our balanced portfolio of assets and our ongoing hedging program position us well for both the current commodity price environment and future potential upside as we develop our attractive resource opportunities. Our primary sources of liquidity are cash generated from our operations and our credit facility.
We attempt to assume the position of operator in all acquisitions of producing properties and will continue to evaluate prospects for leasehold acquisitions and for exploration and development operations in areas in which we own interests. We continue to actively pursue the acquisition of producing properties. To diversify and broaden our asset base, we will consider acquiring the assets or stock in other entities and companies in the oil and gas business. Our main objective in making any such acquisitions will be to acquire income producing assets to build stockholder value through consistent growth in our oil and gas reserve base on a cost-efficient basis.
Our cash flows depend on many factors, including the price of oil and gas, the success of our acquisition and drilling activities and the operational performance of our producing properties. We use derivative instruments to manage our commodity price risk. This practice may prevent us from receiving the full advantage of any increases in oil and gas prices above the maximum fixed amount specified in the derivative agreements and subjects us to the credit risk of the counterparties to such agreements. Since all our derivative contracts are accounted for under mark-to-market
accounting, we expect continued volatility in gains and losses on mark-to-market
derivative contracts in our consolidated statement of operations as changes occur in the NYMEX price indices.
Market Conditions and Commodity Prices:
Our financial results depend on many factors, particularly the price of natural gas and crude oil and our ability to market our production on economically attractive terms. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by weather conditions, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. In addition, our realized prices are further impacted by our derivative and hedging activities. We derive our revenue and cash flow principally from the sale of oil, natural gas and NGLs. As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil, natural gas and NGLs. We sell our oil and natural gas on the open market at prevailing market prices or through forward delivery contracts. Because some of our operations are located outside major markets, we are directly impacted by regional prices regardless of Henry Hub, WTI or other major market pricing. The market price for oil, natural gas and NGLs is dictated by supply and demand; consequently, we cannot accurately predict or control the price we may receive for our oil, natural gas and NGLs. Index prices for oil, natural gas, and NGLs have improved since the lows of 2020 however we expect prices to remain volatile and consequently cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our capital program, production volumes or revenues.
Critical Accounting Estimates:
Proved Oil and Gas Reserves
Proved oil and gas reserves directly impact financial accounting estimates, including depreciation, depletion and amortization. Proved reserves represent estimated quantities of natural gas, crude oil, condensate, and natural gas liquids that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. The process of estimating quantities of proved oil and gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time.
Depreciation, Depletion and Amortization for Oil and Gas Properties
The quantities of estimated proved oil and gas reserves are a significant component of our calculation of depletion expense and revisions in such estimates may alter the rate of future expense. Holding all other factors constant, if reserves were revised upward or downward, earnings would increase or decrease respectively. Depreciation, depletion and amortization of the cost of proved oil and gas properties are calculated using the unit-of-production
method. The reserve base used to calculate depletion, depreciation or amortization is the sum of proved developed reserves and proved undeveloped reserves for leasehold acquisition costs and the cost to acquire proved properties. The reserve base includes only proved developed reserves for lease and well equipment costs, which include development costs and successful exploration drilling costs. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account.
Liquidity and Capital Resources:
Our primary sources of liquidity are cash generated from our operations, through our producing oil and gas properties, field services business and sales of acreage.
Net cash provided by operating activities for the year ended December 31, 2021 was $28.6 million, compared to $16.4 million in the prior year. Excluding the effects of significant unforeseen expenses or other income, our cash flow from operations fluctuates primarily because of variations in oil and gas production and prices or changes in working capital accounts. Our oil and gas production will vary based on actual well performance but may be curtailed due to factors beyond our control.
Our realized oil and gas prices vary due to world political events, supply and demand of products, product storage levels, and weather patterns. We sell the majority of our production at spot market prices. Accordingly, product price volatility will affect our cash flow from operations. To mitigate price volatility, we sometimes lock in prices for some portion of our production through the use of derivatives.
If our exploratory drilling results in significant new discoveries, we will have to expend additional capital to finance the completion, development, and potential additional opportunities generated by our success. We believe that, because of the additional reserves resulting from the successful wells and our record of reserve growth in recent years, we will be able to access sufficient additional capital through bank financing.
Maintaining a strong balance sheet and ample liquidity are key components of our business strategy. For 2022, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our 2022 capital budget is reflective of 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 assets, or enter into strategic joint ventures. We are actively in discussions with financial partners for funding to develop our asset base and, if required, pay down our revolving credit facility should our borrowing base become limited due to the deterioration of commodity prices.
The Company maintains a Credit Agreement with a maturity date of February 11, 2023, providing for a credit facility totaling $300 million, with a borrowing base of $50 million. As of March 31, 2022, the Company has $9 million in outstanding borrowings and $41 million in availability under this facility. The bank reviews the borrowing base semi-annually and, at their discretion, may decrease or propose an increase to the borrowing base relative to a re-determined
estimate of proved oil and gas reserves. The next borrowing base review is scheduled for May 2022. Our oil and gas properties are pledged as collateral for the line of credit and we are subject to certain financial and operational covenants defined in the agreement. We are currently in compliance with these covenants and expect to be in compliance over the next twelve months. If we do not comply with these covenants on a continuing basis, the lenders have the right to refuse to advance additional funds under the facility and/or declare all principal and interest immediately due and payable. Our borrowing base may decrease as a result of lower natural gas or oil prices, operating difficulties, declines in reserves, lending requirements or regulations, the issuance of new indebtedness or for other reasons set forth in our revolving credit agreement. In the event of a decrease in our borrowing base due to declines in commodity prices or otherwise, our ability to borrow under our revolving credit facility may be limited and we could be required to repay any indebtedness in excess of the re-determined
borrowing base.
Our credit agreement required us to hedge a portion of our production as forecasted for the PDP reserves included in our borrowing base review engineering reports. Accordingly, the Company has in place the following swap agreements for oil and natural gas.
Swap Agreements
Natural Gas (MMBTU)
1,528,000
377,000
$ 3.15
$ 3.87
Oil (barrels)
530,600
114,200
$ 66.20
$ 74.07
The successful development of these reservoirs has proven-up
drilling locations on our nearby 2,600-acre
leasehold block in which the Company holds between 14% and 56% interest. It is anticipated that development of as many as 54 additional horizontal wells on this 2,600-acre
block will occur over the coming years. The cost of such development will be approximately $370 million with the Company’s share being approximately $170 million. The actual number of wells that will be drilled, the cost, and the timing of drilling will vary based upon many factors, including commodity market conditions.
The Company is currently participating with SEM Operating Company, LLC in four horizontal wells in Irion County, Texas with 10.3% interest for an estimated investment of $2.35 million. These wells are expected to be online in the second quarter of 2022.
Additional Permian Basin development drilling plans in 2022 include the drilling of nine 2.5-mile
horizontal wells with BTA Oil Producers in Reagan County, Texas. The Company will have an average of 43.67 % interest in these wells with an expected capital outlay of $40.5 million through completion. These wells are scheduled to be drilled in June and completed in 2022.
Also in 2022, in the Permian Basin of West Texas, the Company plans to drill four horizontal wells with ConocoPhilips in Martin County with an average of 38% interest. The total capital expenditure for these wells is expected to be $15 million. Additional drilling and future development plans will be established based on an expectation of available cash flows from operations and availability of funds under our revolving credit facility.
The Company maintains an acreage position of 17,148 gross (10,640 net) acres in the Permian Basin in West Texas, primarily in Reagan, Upton, Martin, and Midland counties and we believe this acreage has significant resource potential in as many as 10 reservoirs, including benches of the Spraberry, Jo Mill, and Wolfcamp that support the potential drilling of as many as 180 additional horizontal wells.
In 2021, in the Scoop/Stack Play of Oklahoma, the Company participated for 11.25% interest in the drilling of four wells and the completion of three of these wells in December that were placed on production in early January of 2022. The Company had an expenditure of approximately $2.2 million. In the first quarter of 2022, the Company received and approved proposals from Ovintiv Mid-Continent,
Inc. for the drilling of four horizontal wells in Canadian County, Oklahoma. Drilling will begin in April and completion of these wells are expected in June of this year. The Company will participate for 9.38% and expects total drilling and completion costs to be approximately $1.8 million.
In Oklahoma, the Company’s horizontal activity is primarily focused in Canadian, Grady, Kingfisher, Garfield, Major, and Garvin counties where we have approximately 200 net leasehold acres in the Scoop/Stack Play. We believe this acreage has significant additional resource potential that could support the drilling of as many as 54 new horizontal wells based on an estimate of six 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.
To supplement cash flow and finance our drilling program during 2021, the Company sold leasehold rights through one transaction in Texas, receiving gross proceeds of approximately $1.45 million in exchange for 116 net leasehold acres. In the first quarter of 2022, The Company sold 1,809 net leasehold acres in Regan and Midland Counties, Texas through two transactions receiving gross proceeds of $14.1 million and retaining certain over-riding royalty interests. These sales have allowed the Company to reduce its bank debt to $9 million, as of March 31, 2022, with the right to borrow up to $50 million under its current revolving line of credit.
The majority of our capital spending is discretionary, and the ultimate level of expenditures will be dependent on our assessment of the oil and gas business environment, the number and quality of oil and gas prospects available, the market for oilfield services, and oil and gas business opportunities in general.
The Company has a stock repurchase program in place, spending under this program in 2021 and 2020 was $145 thousand and $710 thousand, respectively. The Company expects continued spending under the stock repurchase program in 2022.
Results of Operations:
2021 and 2020 Compared
We reported a net income of $2.1 million for 2021, or $1.05 per share, compared to a net loss of $2.3 million, or $1.16 per share for 2020. The current year net income reflects commodity price increases partially offset by losses related to the valuation of derivative instruments. The significant components of income and expense are discussed below.
Oil, NGL and gas sales
increased $36.1 million, or 97.6% to $73.1 million for the year ended December 31, 2021 from $37.0 million for the year ended December 31, 2020. Crude oil, NGL and natural gas sales vary due to changes in volumes of production sold and realized commodity prices. Our realized prices at the well head increased an average of $30.38 per barrel, or 79.9% on crude oil, increased an average of $15.75 per barrel, or 140.4% on NGL and increased $2.29 per Mcf, or 184.3% on natural gas during 2021 as compared to 2020.
Our crude oil production increased by 5,000 barrels, or 0.68% to 738,000 barrels for the year ended December 31, 2021 from 733,000 barrels for the year ended December 31, 2020. Our NGL production decreased by 21,000 or 4.85% to 416,000 for the year ended December 31, 2021 from 437,000 barrels for the year ended December 31, 2020. Our natural gas production decreased by 145 MMcf, or 4.29% to 3,236 MMcf for the year ended December 31, 2021 from 3,381 MMcf for the year ended December 31, 2020. The changes in crude oil, NGL and natural gas production volumes are a result of the natural decline of existing properties slightly offset by new wells placed in production.
The following table summarizes the primary components of production volumes and average sales prices realized for the years ended December 31, 2021 and 2020 (excluding realized gains and losses from derivatives).
Twelve months ended
December 31,
Increase /
(Decrease)
Increase /
(Decrease)
Barrels of Oil Produced
738,000
733,000
5,000
0.68 %
Average Price Received
$ 68.39
$ 38.02
$ 30.38
79.91 %
Oil Revenue (In 000’s)
$ 50,474
$ 27,865
$ 22,609
81.14 %
Mcf of Gas Sold
3,236,000
3,381,000
(145,000 )
(4.29 )%
Average Price Received
$ 3.53
$ 1.24
$ 2.29
184.25 %
Gas Revenue (In 000’s)
$ 11,432
$ 4,202
$ 7,230
172.06 %
Barrels of Natural Gas Liquids Sold
416,000
437,000
(21,000 )
(4.85 )%
Average Price Received
$ 26.97
$ 11.22
$ 15.75
140.36 %
Natural Gas Liquids Revenue (In 000’s)
$ 11,220
$ 4,906
$ 6,314
128.70 %
Total Oil & Gas Revenue (In 000’s)
$ 73,126
$ 36,973
$ 36,153
97.78 %
Oil, Natural Gas and NGL Derivatives
We do not apply hedge accounting to any of our commodity based derivatives, thus changes in the fair market value of commodity contracts held at the end of a reported period, referred to as mark-to-market
adjustments, are recognized as unrealized gains and losses in the accompanying condensed consolidated statements of operations. As oil and natural gas prices remain volatile, mark-to-market
accounting treatment creates volatility in our revenues.
The following table summarizes the results of our derivative instruments for the twelve months ended December 2021 and 2020:
Twelve months ended
December 31,
Oil derivatives - realized (losses) gains
$ (3,212 )
$ 5,697
Oil derivatives - unrealized (losses) gains
(4,055 )
Total (losses) gains on oil derivatives
$ (7,267 )
$ 5,858
Natural gas derivatives - realized (losses) gains
(1,833 )
Natural gas derivatives - unrealized (losses)
(859 )
(351 )
Total (losses) gains on natural gas derivatives
$ (2,692 )
$
Total (losses) gains on oil and natural gas
$ (9,959 )
$ 5,983
Prices received for the twelve months ended December 31, 2021 and 2020, respectively, including the impact of derivatives were:
Increase /
(Decrease)
Increase /
(Decrease)
Oil Price
$ 64.04
$ 45.79
$ 18.25
39.9 %
Gas Price
$ 2.97
$ 1.38
$ 1.58
114.4 %
NGL Price
$ 26.97
$ 11.22
$ 15.75
140.4 %
Field service income
increased $0.7 million, or 6.3% to $11.8 million for the year ended December 31, 2021 from $11.1 million for the year ended December 31, 2020. This increase is a combined result of increased utilization and rates charged to customers as oil and gas prices improved during 2021. Workover rig services, hot oil treatments, saltwater hauling and disposal represent the bulk of our field service operations.
Lease operating expenses
increased $4.8 million, or 20.9% to $27.8 million for the year ended December 31, 2021 from $23.0 million for the year ended December 31, 2020. This increase is primarily due to returning higher lifting cost properties to production during 2021 as commodity prices improved, combined with higher production taxes related to higher commodity prices.
Field service expense
increased $2.6 million, or 28.9% to $11.6 million for the year ended December 31, 2021 from $9.0 million for the year ended December 31, 2020. Field service expenses primarily consist of wages and vehicle operating expenses which have increased during 2021 related to increased utilization of our equipment services.
Depreciation, depletion, amortization and accretion on discounted liabilities
decreased $1.9 million, or 6.7% to $26.3 million for the year ended December 31, 2021 from $28.2 million for the year ended December 31, 2020. The DD&A expense is primarily attributable to our properties in West Texas and Oklahoma, reflecting the declining cost basis of those properties.
General and administrative expense
decreased $4.6 million, or 30.7% to $10.4 million for the year ended December 31, 2021 from $15.0 million for the year ended December 31, 2020. This decrease in 2021 reflects cost reductions put in place during 2020 responding to sharply lower commodity prices, primarily reductions in staff and compensation.
Gain on sale and exchange of assets
of $1.5 million for the year ended December 31, 2021 and $15.8 million for the year ended December 31, 2020 consists principally of sales of deep rights in undeveloped acreage in West Texas and, in 2020, also included the sale of marginal wells in West Virginia.
Interest
expense increased $0.1 million, or 5.3% to $2.0 million for the year ended December 31, 2021 from $1.9 million for the year ended December 31, 2020. The average interest rate paid on outstanding bank borrowings under its revolving credit facility during 2021 and 2020 were
5.29% and 3.95%, respectively. As of December 31, 2021 and 2020, the total outstanding borrowings under its revolving credit facility were $36.0 million and $37.0 million, respectively.
Tax
expense of $2.5 million and tax benefit of $0.5 million were recorded for the years ended December 31, 2021 and 2020, respectively. The change in our income tax provision was primarily due to the increase in pre-tax
income for the year ended December 31, 2021.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
We are a smaller reporting company and therefore no response is required pursuant to this Item.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The consolidated financial statements and supplementary information included in this Report are described in the Index to Consolidated Financial Statements at Page
of this Report.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.

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ITEM 9A. CONTROLS AND PROCEDURES
Item 9A.
CONTROLS AND PROCEDURES.
As of the end of the period covered by this Annual Report on Form 10-K,
our principal executive officer and principal financial officer have evaluated the effectiveness of our “disclosure controls and procedures” (“Disclosure Controls”). Disclosure Controls, as defined in Rule 13a-15(e)
of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), are procedures that are designed with the objective of ensuring that information required to be disclosed in our reports filed under the Exchange Act, such as this Annual Report, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Disclosure Controls are also designed with the objective of ensuring that such information is accumulated and communicated to our management, including the chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.
Our management, including the chief executive officer and chief financial officer, does not expect that our Disclosure Controls will prevent all error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions.
Members of our management, including our chief executive officer and chief financial officer, have evaluated the effectiveness of our disclosure controls and procedures, as defined by paragraph (e) of Exchange Act Rules 13a-15
or 15d-15,
as of December 31, 2021 the end of the period covered by this Report. Based upon that evaluation, these officers concluded that our disclosure controls and procedures were effective as of December 31, 2021.
Management’s Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f)
and 15d-15(f)
under the Exchange Act. Our internal control over financial reporting is a process designed to provide reasonable assurance that assets are safeguarded against loss from unauthorized use or disposition, transactions are executed in accordance with appropriate management authorization and accounting records are reliable for the preparation of financial statements in accordance with U.S. generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2021. Management based this assessment on criteria for effective internal control over financial reporting described in “Internal Control - Integrated Framework (2013)” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management’s assessment included an evaluation of the design of our internal control over financial reporting and testing of the operational effectiveness of its internal control over financial reporting. Management reviewed the results of its assessment with the Audit Committee of our Board of Directors.
Based on this assessment, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2021.
This Annual Report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this Annual Report.
There have been no changes in our internal controls over financial reporting during the fourth fiscal quarter ended December 31, 2021 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

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ITEM 9B. OTHER INFORMATION
Item 9B.
OTHER INFORMATION.
None.
PART III

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.
Information relating to the Company’s Directors, nominees for Directors and executive officers will be included in the Company’s definitive proxy statement relating the Company’s Annual Meeting of Stockholders to be held in June, 2022, and which is incorporated herein by reference.

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ITEM 11. EXECUTIVE COMPENSATION
Item 11.
EXECUTIVE COMPENSATION.
Information relating to executive compensation will be included in the Company’s definitive proxy statement relating to the Company’s Annual Meeting of Stockholders to be held in June, 2022, and which is incorporated herein by reference.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
Item 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.
Information relating to security ownership of certain beneficial owners and management will be included in the Company’s definitive proxy statement relating to the Company’s Annual Meeting of Stockholders to be held in June, 2022, and which is incorporated herein by reference.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.
Information relating to certain transactions by Directors and executive officers of the Company will be included in the Company’s definitive proxy statement relating to the Company’s Annual Meeting of Stockholders to be held in June, 2022, and which is incorporated herein by reference.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Item 14.
PRINCIPAL ACCOUNTANT FEES AND SERVICES.
Information relating to principal accountant fees and services will be included in the Company’s definitive proxy statement relating to the Company’s Annual Meeting of Stockholders to be held in June, 2022, and which is incorporated herein by reference.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Item 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
The following documents are filed as part of this Report:
1. Financial statements (Index to Consolidated Financial Statements at page
of this Report)
2. Financial Statement Schedules (Index to Consolidated Financial Statements - Supplementary Information at page
of this Report)
3. Exhibits:
3.1
Certificate of Incorporation of PrimeEnergy Resources Corporation, as amended and restated of December 21, 2018, (filed as Exhibit 3.1 of PrimeEnergy Resources Corporation Form 8-K on December 27, 2018, and incorporated herein by reference).
3.2
Bylaws of PrimeEnergy Resources Corporation as amended and restated as of April 24, 2020 (filed as Exhibit 3.2 of PrimeEnergy Resources Corporation Form 8-K on April 27, 2020 and incorporated herein by reference).
10.18
Composite copy of Non-Statutory Option Agreements (Incorporated by reference to Exhibit 10.18 of PrimeEnergy Resources Corporation Form 10-K for the year ended December 31, 2004).
10.22.5.10
Third Amended and Restated Credit Agreement dated as of February 15, 2017 among PrimeEnergy Resources Corporation, as Borrower, Compass Bank, as Administrative Agent and Lender, Wells Fargo, National Association, as Document Agent, the Lenders Party Hereto (Compass Bank, Wells Fargo, National Association, Citibank, N.A.) and BBVA Compass Bank, as Letter of Credit Issuer and Sole Lead Arranger and Sole Bookrunner (Incorporated by reference to Exhibit 10.22.5.10 to PrimeEnergy Resources Corporation Form 10-K for the year ended December 31, 2016).
10.22.5.10.1
FIRST AMENDMENT TO THIRD AMENDED AND RESTATED CREDIT AGREEMENT dated as of December 22, 2017 among PRIMEENERGY CORPORATION, as Borrower, THE LENDERS PARTY HERETO, COMPASS BANK, as Administrative Agent, WELLS FARGO BANK, NATIONAL ASSOCIATION, as Documentation Agent, and BBVA COMPASS, as Sole Lead Arranger and Sole Book Runner, (Incorporated by reference to Exhibit 10.22.5.10.1 to PrimeEnergy Corporation Form 10-K for the year ended December 31, 2017).
10.22.5.10.2
SECOND AMENDMENT TO THIRD AMENDED AND RESTATED CREDIT AGREEMENT dated as of July 17, 2018 among PRIMEENERGY CORPORATION, as Borrower, THE LENDERS PARTY HERETO, COMPASS BANK, as Administrative Agent, WELLS FARGO BANK, NATIONAL ASSOCIATION, as Documentation Agent, and BBVA COMPASS, as Sole Lead Arranger and Sole Book Runner, (Incorporated by reference to Exhibit 10.22.5.10.2 to PrimeEnergy Corporation Form 10-Q for the quarter ended June 30, 2018).
10.22.5.10.3
THIRD AMENDMENT TO THIRD AMENDED AND RESTATED CREDIT AGREEMENT dated as of December 27, 2018, among PRIMEENERGY RESOURCES CORPORATION, as Borrower, THE LENDERS PARTY HERETO, COMPASS BANK, as Administrative Agent, WELLS FARGO BANK, NATIONAL ASSOCIATION, as Documentation Agent, and BBVA COMPASS, as Sole Lead Arranger and Sole Book Runner (Incorporated by reference to Exhibit 10.22.5.10.3 to PrimeEnergy Resources Corporation Form 10-K for the year ended December 31, 2018).
Exhibit No.
10.22.5.10.4
FOURTH AMENDMENT TO THE THIRD AMENDED AND RESTATED CREDIT AGREEMENT dated as of May 8, 2020 among PRIMEENERGY RESOURCES CORPORATION, as Borrower, THE LENDERS PARTY HERETO, BBVA USA (f/k/a COMPASS BANK), as Administrative Agent, WELLS FARGO BANK, NATIONAL ASSOCIATION, as Documentation Agent, and BBVA USA, as Sole Lead Arranger and Sole Book Runner (Incorporated by reference to 10.22.5.4 to PrimeEnergy Resources Corporation Form 10-Q for the quarter ended September 30, 2020).
10.22.5.10.5
FIFTH AMENDMENT TO THIRD AMENDED AND RESTATED CREDIT AGREEMENT dated as of September 4, 2020, among PRIMEENERGY RESOURCES CORPORATION, as Borrower, THE LENDERS PARTY HERETO, BBVA USA (f/k/a COMPASS BANK,) as Administrative Agent, WELLS FARGO BANK, NATIONAL ASSOCIATION, as Documentation Agent, and BBVA USA, as Sole Lead Arranger and Sole Book Runner (Incorporated by reference to 10.22.5.5 to PrimeEnergy Resources Corporation Form 10-Q for the quarter ended September 30, 2020).
10.22.5.10.6
SIXTH AMENDMENT TO THIRD AMENDED AND RESTATED CREDIT AGREEMENT dated as of FEBRUARY 11, 2021, among PRIMEENERGY RESOURCES CORPORATION, as Borrower, THE GUARANTORS PARTY HERETO, THE LENDERS PARTY, HERETO, BBVA USA, as Administrative Agent and BBVA USA, as Sole Lead Arranger and Sole Book Runner (Incorporated by reference to Exhibit 10.22.5.10.6 to PrimeEnergy Resources Corporation Form 8-K dated February 16, 2021).
10.22.5.10.7
SEVENTH AMENDMENT TO THIRD AMENDED AND RESTATED CREDIT AGREEMENT dated as of December 20, 2021 among PRIMEENERGY RESOURCES CORPORATION, as Borrower, THE GUARANTORS PARTY HERETO, THE LENDERS PARTY HERETO, CITIBANK, N.A., as Administrative Agent, and CITIBANK, N.A., as Sole Lead Arranger and Sole Book Runner (filed herewith).
10.22.5.11
Amended, Restated and Consolidated Guaranty dated as of February 15, 2017, among PrimeEnergy Management Corporation, Prime Operating Company, Eastern Oil Well Service Company, Southwest Oilfield Construction Company, EOWS Midland Company and Prime Offshore L.L.C. in favor of Compass Bank, as Administrative Agent for the Lenders (Incorporated by reference to Exhibit 10.22.5.11 to PrimeEnergy Resources Corporation Form 10-K for the year ended December 31, 2016).
10.22.5.12
Amended, Restated and Consolidated Pledge and Security Agreement dated as of February 15, 2017, among PrimeEnergy Resources Corporation, PrimeEnergy Management Corporation, Prime Operating Company, Eastern Oil Well Service Company, Southwest Oilfield Construction Company, EOWS Midland Company and Prime Offshore L.L.C. and Compass Bank, as Administrative Agent for the Secured Parties (Incorporated by reference to Exhibit 10.22.5.12 to PrimeEnergy Resources Corporation Form 10-K for the year ended December 31, 2016).
10.22.5.13
Amended, Restated and Consolidated Deed of Trust, Mortgage, Security Agreement, Assignment of Production and Financing Statement Dated as of May 5, 2017 (Incorporated by reference to Exhibit 10.22.5.13 to PrimeEnergy Resources Corporation Form 10-Q for the quarter ended March 31, 2017).
Exhibit No.
10.22.5.13.1
THIS FIRST AMENDMENT TO AMENDED, RESTATED AND CONSOLIDATED DEED OF TRUST, MORTGAGE, SECURITY AGREEMENT, ASSIGNMENT OF PRODUCTION AND FINANCING STATEMENT (this “Amendment”) is made and entered into as of December 20, 2021, by PRIMEENERGY RESOURCES CORPORATION, a Delaware corporation, formerly known as PrimeEnergy Corporation (“Prime”) and PRIMEENERGY MANAGEMENT CORPORATION, a New York corporation (“PEMC,” and Prime and PEMC herein, individually and collectively, “Grantor”), and CITIBANK, N.A., as Administrative Agent for the benefit of the Secured Parties (in such capacity and together with its successors and assigns in such capacity, “Beneficiary”).
10.22.5.14
Deed of Trust, Mortgage, Security Agreement, Assignment of Production and Financing Statement Dated as of May 5, 2017 (Incorporated by reference to Exhibit 10.22.5.14 to PrimeEnergy Resources Corporation Form 10-Q for the quarter ended March 31, 2017).
10.22.5.14.1
FIRST AMENDMENT TO DEED OF TRUST, MORTGAGE, SECURITY AGREEMENT, ASSIGNMENT OF PRODUCTION AND FINANCING STATEMENT (this “Amendment”) is made and entered into as of December 20, 2021, by PRIMEENERGY RESOURCES CORPORATION, a Delaware corporation, formerly known as PrimeEnergy Corporation (“Prime”) and PRIMEENERGY MANAGEMENT CORPORATION, a New York corporation (“PEMC,” and Prime and PEMC herein, individually and collectively, “Grantor”), and CITIBANK, N.A., as Administrative Agent for the benefit of the Secured Parties (in such capacity and together with its successors and assigns in such capacity, “Beneficiary”)
10.22.5.14.2
THIS SECOND AMENDMENT TO AMENDED, RESTATED AND CONSOLIDATED MORTGAGE OF OIL AND GAS PROPERTY, SECURITY AGREEMENT, ASSIGNMENT OF PRODUCTION AND FINANCING STATEMENT (this “Amendment”) is made and entered into as of December 20, 2021, between PRIMEENERGY RESOURCES CORPORATION, a Delaware corporation, formerly known as PrimeEnergy Corporation (“Prime”) and PRIMEENERGY MANAGEMENT CORPORATION, a New York corporation (“PEMC,” and Prime and PEMC herein, individually and collectively, “Mortgagor”), and CITIBANK, N.A., as Administrative Agent for the benefit of the Secured Parties (in such capacity and together with its successors and assigns in such capacity, “Mortgagee”).
PrimeEnergy Resources Corporation Code of Business Conduct and Ethics, as amended December 16, 2011 (Incorporated by reference to Exhibit 14 of PrimeEnergy Resources Corporation Form 10-K for the year ended December 31, 2011).
Subsidiaries (filed herewith).
Consent of Ryder Scott Company, L.P. (filed herewith).
31.1
Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended (filed herewith).
31.2
Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended (filed herewith).
32.1
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).
32.2
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).
99.1
Summary Reserve Report dated March 3, 2022, of Ryder Scott Company, L.P. (filed herewith).
Exhibit No.
101.INS
Inline XBRL (eXtensible Business Reporting Language) Instance Document (filed herewith)
101.SCH
Inline XBRL Taxonomy Extension Schema Document (filed herewith)
101.CAL
Inline XBRL Taxonomy Extension Calculation Linkbase Document (filed herewith)
101.DEF
Inline XBRL Taxonomy Extension Definition Linkbase Document (filed herewith)
101.LAB
Inline XBRL Taxonomy Extension Label Linkbase Document (filed herewith)
101.PRE
Inline XBRL Taxonomy Extension Presentation Linkbase Document (filed herewith)
Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)