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. Our subsidiary, PrimeEnergy Management
Corporation (PEMC), acts as the managing general partner of one oil and gas limited partnerships (the Partnerships), and acts as the managing trustee of one asset and income business trusts (the Trusts).
Exploration, Development and Recent Activities
The Companys activities include development and exploratory drilling. Our strategy is to develop the Companys 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 todays 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. For 2021, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our 2021 capital budget 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 accordance with SEC rules governing the scheduling of development of proved undeveloped (PUD) reserves, our
year-end reserve report includes only those three wells that were slated to be drilled in 2021 along with 10 PUD locations that at year-end 2020 had been drilled but not
yet completed. The three new wells drilled in the first quarter of 2021 and the six wells drilled in 2020 on the same Upton County, Texas tract are slated to be completed and on production by the end of the second quarter of 2021. The Company has an
average of 47.5% interest in these nine wells. The remaining four PUD horizontal wells, drilled but not completed at year-end, are located in Grady County, Oklahoma. Of these, the Company has 10% interest in
one well and less than one percent interest in each of three wells.
Since the start of our West Texas horizontal drilling program in 2015
and through the first quarter of 2021 the Company has participated in 77 horizontal wells in the Permian Basin, one of which was drilled and brought into production in 2020. As of year-end, the Company has
invested approximately $108 MM in this drilling program, including over $4 million in six wells drilled in 2020 that will be completed in 2021. In addition, the Company has invested another $3.2 million in three new horizontals drilled in
the first quarter of 2021. All nine of these wells are designated as proved undeveloped in the year-end reserve report and are to be completed and on-line by the end of
the second quarter of 2021. Of the total 77 horizontal wells in this program, the Company has an average of 30.75% 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 leasehold acres with interest between 14% and 56%, depending on the particular lease and depth being developed. In 2018, in this block, eight wells drilled horizontally in the Wolfcamp B, were participated in for 49%
interest and brought on production in February, 2019. This is believed to be full development of the Wolfcamp B reservoir for this lease block. Future development is expected in the Upper Wolfcamp, Jo Mill, and Lower Spraberry reservoirs
for this block, following
4
Table of Contents
the 2019 successful development of these reservoirs on our offset 1,280 acre lease block of the Kashmir Tract. Given the favorable results achieved by the initial three wells on the 1,280 block
it is expected that as many as 54 additional horizontals will be developed on this 3,260 acre block in the near future. The cost of development would be approximately $370.6 million with the Companys share being approximately
$170.8 million. In addition to the 54 wells likely to be drilled for these three reservoirs, there is a fourth target reservoir, the Middle Spraberry, that 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 Companys 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 1,280 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 spud in the first quarter of 2020 with six being fully drilled by May, 2020. The three remaining wells were drilled in the first
quarter of 2021. All nine of these wells are slated for completion and to be on production by the end of the second quarter of 2021. Our average 47.5% share of the cost of these nine horizontal wells will be approximately $26.7 million in
total. In addition to the nine new development locations in the Wolfcamp A, Jo Mill and Lower Sprayberry, four locations in the Middle Spraberry will be considered for future development at an estimated gross cost
of approximately $30.2 million with the Companys share being approximately $14.2 million.
Also in the Permian Basin of
West Texas, we are developing a 965 acre block with Connoco Phillips 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 where Connoco Phillips is the operator. No near-term additional drilling plans have been received from Connoco Phillips, however, offset operators have been actively drilling and their results are encouraging for the future development of
multiple landing zones within this acreage block.
In 2020, the Company also added reserves through a 1% Overriding Royalty Interest
(ORRI) in one horizontal well and 0.56% ORRI in 10 additional horizontal wells in Midland County, Texas.
In Central Reagan County, of
West Texas, during 2020, the Company sold deep rights covering approximately 1,950 acres for net proceeds of $10.8 million.
As of
December 31, 2020, we had net capitalized costs related to proved oil and gas properties of $185,098 million. Total expenditures for the acquisition, exploration and development of our properties during 2020 were $8.57 million as we
continue development under the programs discussed above. Proved reserves as of December 31, 2020, were 10.4 MMBOE which consisted of 69% proved developed reserves.
In 2020, the Company acquired approximately 232 net acres in Reagan County, Texas for $343,900 and between 15 and 16.66% working interest in
53 oil and gas wells and 16.66% working interest in one salt water disposal well. We also acquired net acreage in Upton County located where the Company currently has leasehold acreage and where future horizontal drilling will likely occur. In
addition, the Company acquired 9.36 acres in Upton County, Texas for $5,100, where the Company has leasehold acreage with expected future horizontal development.
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. DoublePoint Energy now in the process of being acquired by Pioneer Natural Resources, entered into a joint development agreement for the horizontal
development of lands located in Reagan County, Texas in February of 2021 with PrimeEnergy . The agreement covers approximately 3,680 gross acres of blocked up leasehold to allow for 1.5 and 2 mile horizontal laterals. We believe this agreement
represents significant future value for PrimeEnergy.
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. In order 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.
5
Table of Contents
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., PropertiesReserves, 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 760 active wells, including producing, saltwater disposal, injection, and supply
wells: 167 through the Houston office, 331 through the Midland office, and 262 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 has acted as managing general partner of various partnerships, trusts and joint ventures.
PEMC, as managing general partner of the Partnerships and managing trustee of the Trusts, is responsible for all Partnership and Trust
activities, the drilling of development wells and the production and sale of oil and gas from productive wells. PEMC also provides administration, accounting and tax preparation for the Partnerships and Trusts from our offices in Houston, Texas.
PEMC is liable for all debts and liabilities of the Partnerships and Trusts, to the extent that the assets of a given limited partnership or trust are not sufficient to satisfy its obligations. We stopped sponsoring partnerships and trusts in 1992.
As we entered 2021, we only have one partnership and one trust remaining. All other partnerships and the other trusts have been liquidated. The aggregate number of limited partners in the Partnerships and beneficial owners of the Trusts now
administered by PEMC is approximately 69.
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
6
Table of Contents
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 FERCs 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 FERCs 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 FERCs 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 FERCs 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
7
Table of Contents
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 FERCs 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 FERCs
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
8
Table of Contents
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 RCRAs 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,
9
Table of Contents
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 EPAs and the USACEs 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 CWAs 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
10
Table of Contents
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 EPAs 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 21 st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The Paris Agreement entered into force in November
2016. Although this agreement does not create any binding obligations for nations to limit their GHG emissions, it does include pledges from participating nations to voluntarily limit or reduce future emissions. In June 2017, President Trump stated
that the United States would withdraw from the Paris Agreement, but may enter into a future international agreement related to GHGs. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which
would result in an effective exit date of November 2020. The United States adherence to the exit process is uncertain, and the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are
unclear at this time. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations
on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations.
Substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce and lower the value of our
reserves. 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 Earths 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.
11
Table of Contents
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 agencys 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.
12
Table of Contents
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 2019, nor do we anticipate that such expenditures will be material in 2020.
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. The price of oil and natural gas has fallen
significantly since the beginning of 2020, due in part to failed Organization of Petroleum Exporting Countries (OPEC) negotiations as well as concerns about the COVID-19 pandemic and its impact on
the worldwide economy and global demand for oil and gas. The resulting precipitous decline in oil and gas pricing experienced during March 2020, through the date of this report, if prolonged, or a further deterioration of the market price for oil
and natural gas, will negatively impact our cash flows.
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.
13
Table of Contents
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 Companys total oil and gas sales made which represented more than 10% of the Companys oil and gas sales in the year 2020.
Oil Purchasers:
Apache Corporation
47
%
Plains All American Inc.
19
%
Gas Purchasers:
Apache Corporation
42
%
Targa Pipeline Mid-Continent West Tex, LLC
12
%
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, 2020, we had 96 full time employees, 26 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 70 employees who were primarily involved in our district operations in Midland, Texas, Elmore City and Oklahoma City, Oklahoma.
14
Table of Contents
Text extracted from the filing as submitted to EDGAR. Formatting, tables and exhibits are simplified for reading; the original document is authoritative for anything you rely on.