PRIMEENERGY RESOURCES CORP - Annual Report: 2021 (Form 10-K)

This Annual Report on Form includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected revenues, projected costs, the potential impact of epidemics and pandemics, including the coronavirus and plans and objectives of management for future operations, are forward-looking statements. Such forward-looking statements are based on our examination of historical operating trends, the information that was used to prepare our estimate of proved reserves as of December 31, 2021, and other data in our possession or available from third parties. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “could,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “plan,” “believe,” or “continue” or similar terminology. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, our assumptions about:

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

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 assets, or enter into strategic joint ventures.

In 2021, nine horizontal wells operated by Apache in Upton County, Texas were completed in the third quarter of 2021 and three horizontal wells operated by Ovintiv 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 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 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 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.

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 laterals. The Company’s investment in these wells is expected to be $15 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 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 presently own producing and properties located primarily in Texas, and Oklahoma, and we own a substantial amount of well servicing equipment.

In the past, the supply of gas has exceeded demand on a cyclical basis, and we are subject to a combination of and/or reduced takes of gas production during summer months. Prolonged could result in reduced field operating income from properties in which we act as operator.

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

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 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.

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 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 Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and 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 waste provisions. However, it is possible that certain oil and natural gas drilling and production wastes now classified as 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.

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 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.

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 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.

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 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.

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 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 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.

Oil Purchasers:
Apache Corporation			48	%
Plains All American Inc.			18	%
Gas Purchasers:
Apache Corporation			52	%
Targa Pipeline Mid-Continent West Tex, LLC			19	%

Item 1A.

RISK FACTORS.

•

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.

•

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.

•

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.

•

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.

•

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.

•

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.

Item 1B.

UNRESOLVED STAFF COMMENTS.

Item 2.

PROPERTIES.

		2021								2020								2019
		Gross				Net				Gross				Net				Gross				Net
Exploratory:
Oil			—				—				—				—				—				—
Gas			—				—				—				—				—				—
Dry			—				—				—				—				—				—
Development:
Oil			12				4.61				1				0.1				18				1.6
Gas			—				—				—				—				—				—
Dry			—				—				—				—				—				—
Total:
Oil			12				4.61				1				0.1				18				1.6
Gas			—				—				—				—				—				—
Dry			—				—				—				—				—				—
			12				4.61				1				0.1				18				1.6

		Gross				Net
Producing wells (1) :
Oil Wells			926				498
Gas Wells			281				66

(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.

		2021				2020				2019
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

		2021				2020				2019
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.

		2021				2020				2019
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

		Developed								Undeveloped								Total
		Gross				Net				Gross				Net				Gross				Net
Leasehold acreage			90,933				25,358				—				—				90,933				25,358
Mineral fee acreage			1,640				117				19,257				417				20,897				534
Total			92,573				25,475				19,257				417				111,830				25,892

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 and therefore classified as Proved Undeveloped in the 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 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 2018, were completed in 2019 converting 24 Mboe of reserves to proved developed. Also in Oklahoma, six wells designated as on December 31, 2018, were brought into production in 2019: five located on our Ruthie tract, and one on our Braum tract.

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 2020, and three that were not drilled until 2021. The three new horizontals along with the six uncompleted wells at 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 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 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 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 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.

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 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 interests in the Partnerships. These interests represent less than 10% of our reserves.

Our 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 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 Region in 2021 was 747 Boe. At December 31, 2021, we had 2,383 MBoe of proved reserves in the 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 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 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 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 reserve report.

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 2021 reserves report.

The above quotations reflect inter-dealer prices, without retail mark-down or commissions, and may not represent actual transactions.

`

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 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.

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

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 accounting, we expect continued volatility in gains and losses on derivative contracts in our consolidated statement of operations as changes occur in the NYMEX price indices.

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 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.

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 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 borrowing base.

The successful development of these reservoirs has drilling locations on our nearby 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 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.

Additional Permian Basin development drilling plans in 2022 include the drilling of nine 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.

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 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.

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.

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 adjustments, are recognized as unrealized gains and losses in the accompanying condensed consolidated statements of operations. As oil and natural gas prices remain volatile, accounting treatment creates volatility in our revenues.

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.

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.

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.

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.

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.

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.

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 were5.29% 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.

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 income for the year ended December 31, 2021.

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.

As of the end of the period covered by this Annual Report on Form 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 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.

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 or 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.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules and 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.

PART IV

 

The following documents are filed as part of this Report:

 

 

 

 

 

46

 

47

 

48

PrimeEnergy Resources Corporation
By:		/s/ Charles E. Drimal, Jr.
		Charles E. Drimal, Jr.
		Chairman, Chief Executive Officer and President