At this time, we do not believe that we are associated with any Superfund site and have not been notified of any claim, liability or damages under CERCLA.
OilWater 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 1990. The OPApollutants, including spills and regulations thereunder impose liability on responsible parties for damages resulting fromleaks of oil spillsand other substances, into or upon navigable waters and adjoining shorelines or in the exclusive economic zone of the United States. Liability under OPAThe discharge of pollutants into regulated waters, including wetland areas, is strict, and under certain circumstances joint and several, and potentially unlimited. A “responsible party” includesprohibited, except in accordance with the ownerterms of a permit issued by the EPA, the U.S. Army Corps of Engineers (the “USACE”) or operator of an onshore facilityanalogous state agency. In September 2015, the EPA and the lessee or permitteeUSACE issued a final rule outlining federal jurisdictional reach under the CWA over waters of the areaU.S., including wetlands, which has since been subject to several revisions. In May 2023, the Supreme Court decided Sackett v. EPA, which significantly narrowed the scope of “waters of the United States.” Under Sackett, the word “waters” refers only to “those relatively permanent, standing or continuously flowing bodies of water forming geographic features that are described in which an offshore facilityordinary parlance as streams, oceans, rivers, and lakes” and to “wetlands that are as a practical matter indistinguishable from waters of the United States.” In August 2023, the EPA finalized a rule amending the definition of “waters of the United States” to conform with the recent Supreme Court decision in Sackett. However, litigation challenging aspects of the January 2023 definition not addressed by Sackett is located. A failureongoing. To the extent future changes expand the scope of the CWA’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. In addition, federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations. We do not expect the costs to comply with OPA’sthe requirements or inadequate cooperation during a spill response action may subject a responsible partyof the CWA to civil or criminal enforcement actions. We are not aware of any action or event that would subject us to liability under OPA and believe that compliance with OPA’s operating requirements will not 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.
U.S. Environmental Protection Agency.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 U.S. Environmental Protection Agency regulations addressRRC 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 operational wastes under threegas-related waste waters, federal actsand 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 fully discussedfrequent 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 paragraphs that follow. The Resource Conservation and Recovery Actavailability of 1976, as amended (“RCRA”), provides a frameworkinjection wells for the safe disposal of discarded materialswastewater from our operations. Increased costs associated with the transportation and the management of solid and hazardous wastes. The direct disposal of operational wastes into offshore waters is also limited underproduced water, including the authoritycost of complying with regulations concerning produced water disposal, may reduce our profitability. The costs associated with the Clean Water Act. When injected underground,disposal of proposed water are commonly incurred by all oil and natural gas wastesproducers, however, and we do not believe that these costs will have a material adverse effect on our operations.
Air Emissions
The federal Clean Air Act and comparable state laws restrict the emission of air pollutants from many sources, such as tank batteries and compressor stations, through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard for ozone from 75 to 70 parts per billion. The EPA approved final attainment/nonattainment designations with the new ozone standards in July 2018 and currently all of the areas in which we operate are regulatedin 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.
Given the long-term trend toward increasing regulation, these and future laws and 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. In December 2023, the EPA finalized New Source Performance Standard (“NSPS”) Subpart OOOOb, which seeks to reduce methane and volatile organic compound emissions from the oil and natural gas source category and NSPS Subpart OOOOc, which create, for the first-time, emission guidelines for existing oil and natural gas sources that would be included in individual states’ implementation plans. These standards expand upon previously issued NSPS Subparts OOOO and OOOOa published by the Underground Injection Control programEPA in 2012 and 2016, respectively. In January 2024, the EPA issued a proposed rule implementing a methane fee required under the Inflation Reduction Act of 2022.
Substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce and lower the value of our reserves. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to represent a major share of global energy use through 2040, and other private sector studies project continued growth in demand for the next two decades. However, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector. Finally, it should also be noted that many scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts and other climatic events; if any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.
Hydraulic Fracturing Activities
Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemicals under pressure into target geological formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations. Recently, there has been increased public concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies, resulting in new legislative and regulatory initiatives that seek to increase the regulatory burden imposed on hydraulic fracturing.
At the federal level, the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act. If wastesAct 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. Also, the federal Bureau of Land Management (“BLM”) published a final rule in 2015 that established new or more stringent standards for performing hydraulic fracturing on federal and Indian lands; however, the BLM rescinded the 2015 rule in 2017.
At the state level, several states have adopted or are classified as hazardous, they mustconsidering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities, or prohibit hydraulic fracturing or high volume hydraulic fracturing altogether. 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 properly transported, using a uniform hazardous waste manifest, documented, and disposed at an approved hazardous waste facility.
Resource Conservation and Recovery Act. The RCRA is the principal federal statute governing the treatment, storage and disposal of hazardous wastes. RCRA imposes stringent operating requirements and liability for failurerequired to meetincur significant added costs to comply with such requirements, on a person who is either a “generator”experience delays or “transporter”curtailment in the pursuit of hazardous wasteexploration, development or an “owner”production activities and perhaps even be precluded from drilling wells.
If new federal, state or “operator” of a hazardous waste treatment, storagelocal laws or disposal facility. At present, RCRA includes a statutory exemptionregulations that allows mostsignificantly 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 wasteactivities 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 classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. As a result, we are not required to comply with a substantial portion of RCRA’s requirements because theimposed on activities adversely affecting that species’ habitat. We may conduct operations generate minimal quantities of hazardous wastes. At various times in the past, proposals have been made to amend RCRA to rescind the exemption that excludeson oil and natural gas explorationleases in areas where certain species that are listed as threatened or endangered are known to exist and production wastes from regulationwhere other species, such as hazardous waste. Repealthe sage grouse, that potentially could be listed as threatened or modificationendangered 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 exemption by administrative, legislativeagency’s 2017 fiscal year. The FWS missed the deadline but reportedly continues to review new species for protected status under the ESA pursuant to the settlement agreement. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. In 2023, Recently, the FWS proposed that the dunes sagebrush lizard, whose habitat includes portions of the Permian Basin, be listed as endangered under the ESA. The designation as threatened or judicial process, or modificationendangered of similar exemptionspreviously unprotected species in applicable state statutes, would increase the volume of hazardous wasteareas where we are required to manage and dispose of and wouldoperate could cause us to incur increased operating expenses.
Clean Water Act. The Clean Water Act and resulting regulations imposes restrictions and controls on the discharge of produced waters and other wastes into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters and to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry into certain coastal and offshore waters. Further, the EPA has adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges.
Costs may be associated with the treatment of wastewatercosts arising from species protection measures or developing and implementing storm water pollution prevention plans. The Clean Water Act and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges for oil and other pollutants and impose liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release. We believe that our operations comply in all material respects with the requirements of the Clean Water Act and state statutes enacted to control water pollution.
Safe Drinking Water Act. Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. The Safe Drinking Water Act establishes a regulatory framework for underground injection, with the main goal being the protection of usable aquifers. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. Hazardous-waste injection well operations are strictly controlled, and certain wastes, absent an exemption, cannot be injected into underground injection control wells. In Louisiana and Texas, no underground injection may take place except as authorized by permit or rule. We currently own and operate various underground injection wells. Failure to abide by the permits could subject us to civil and/or criminal enforcement. We believe we are in compliance in all material respects with the requirements of applicable state and federal underground injection control programs and permits.
Hydraulic Fracturing. Many of our exploration and production operations depend on the use of hydraulic fracturing to enhance production from oil and gas wells. This technology involves the injection of fluids, usually consisting mostly of water but typically including small amounts of several chemical additives, as well as sand into a well under high pressure in order to create fractures in the rock that allow oil or gas to flow more freely to the wellbore. Most of our wells would not be economical without the use of hydraulic fracturing to stimulate production from the well. Hydraulic fracturing operations have historically been overseen by state regulators as part of their oil and gas regulatory programs. However, bills have been introduced in Congress that would subject hydraulic fracturing to federal regulation under the Safe Drinking Water Act. If adopted, these bills could result in additional permitting requirements for hydraulic fracturing operations as well as various restrictionslimitations on those operations. These permitting requirementsour development and restrictions could result in delays in operations at well sites as well as increased costs to make wells productive. Moreover, the bills introduced in Congress would require the public disclosure of certain information regarding the chemical makeup of hydraulic fracturing fluids, many of which are proprietary to the service companies that perform the hydraulic fracturing operations. Such disclosure could make it easier for third parties to initiate litigation against us in the event of perceived problems with drinking water wells in the vicinity of an oil or gas well or other alleged environmental problems. In addition to these federal legislative proposals, some states and local governments have adopted, and others are considering adopting, regulationsproduction activities that could restrict
hydraulic fracturing in certain circumstances, including but not limitedhave a material adverse impact on our ability to requirements regarding chemical disclosure, casingdevelop and cementing of wells, withdrawal of water for use in high-volume hydraulic fracturing of horizontal wells, baseline testing of nearby water wells, and restrictions on the type of additives that may be used in hydraulic fracturing operations. If these types of conditions are adopted, we could be subject to increased costs and possibly limits on the productivity of certain wells.
Greenhouse Gas. In response to studies suggesting that emissions of carbon dioxide and certain other gases may be contributing to global climate change, the United States Congress has considered legislation to reduce emissions of greenhouse gases from sources within the United States between 2012 and 2050. In addition, many states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. The EPA has also begun to regulate carbon dioxide and other greenhouse gas emissions under existing provisions of the Clean Air Act. This includes proposed regulation of methane emissions from the oil and gas sector.produce our reserves. If we are unablewere to recover or pass throughhave a significant portion of our costs related to complying with current and future regulations relating to climate change and GHGs,leases designated as critical or suitable habitat, it could materially affect our operations and financial condition. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of, and access to, capital. Future legislation or regulations adopted to address climate change could also make our products more or less desirable than competing sources of energy.
Consideration of Environmental Issues in Connection with Governmental Approvals. Our operations frequently require licenses, permits and/or other governmental approvals. Several federal statutes, including OCSLA, the National Environmental Policy Act (“NEPA”), and the Coastal Zone Management Act (“CZMA”) require federal agencies to evaluate environmental issues in connection with granting such approvals and/or taking other major agency actions. OCSLA, for instance, requires the U.S. Department of Interior (“DOI”) to evaluate whether certain proposed activities would cause serious harm or damage to the marine, coastal or human environment. Similarly, NEPA requires DOI and other federal agencies to evaluate major agency actions having the potential to significantlyadversely impact the environment. In the coursevalue of such evaluations, an agency would have to prepare an environmental assessment and, potentially, an environmental impact statement. CZMA, on the other hand, aids states in developing a coastal management program to protect the coastal environment from growing demands associated with various uses, including offshore oil and natural gas development. In obtaining various approvals from the DOI, we must certify that we will conduct our activities in a manner consistent with an applicable program.leases.
Lead-Based Paints. Various pieces of equipment and structures we own may have been coated with lead-based paints as was customary in the industry at the time these pieces of equipment were fabricated and constructed. These paints may contain lead at a concentration high enough to be considered a regulated hazardous waste when removed. If we need to remove such paints in connection with maintenance or other activities and they qualify as a regulated hazardous waste, this would increase the cost of disposal. High lead levels in the paint might also require us to institute certain administrative and/or engineering controls required by the Occupational Safety and Health Act and BSEE to ensure worker safety during paint removal.
Air Pollution Control. The Clean Air Act and state air pollution laws adopted to fulfill its mandates provide a framework for national, state and local efforts to protect air quality. Operations utilize equipment that emit air pollutants subject to federal and state air pollution control laws. These laws require utilization of air emissions abatement equipment to achieve prescribed emissions limitations and ambient air quality standards, as well as operating permits for existing equipment and construction permits for new and modified equipment. Air emissions associated with offshore activities are projected using a matrix and formula supplied by BSEE, which has primacy from the EPA for regulating such emissions.
Naturally Occurring Radioactive Materials. Naturally Occurring Radioactive Materials (“NORM”) are materials not covered by the Atomic Energy Act, whose radioactivity is enhanced by technological processing such as mineral extraction or processing through exploration and production conducted by the oil and natural gas industry. NORM wastes are regulated under the RCRA framework, but primary responsibility for NORM regulation has been a state function. Standards have been developed for worker protection, treatment, storage and disposal of NORM waste, management of waste piles, containers and tanks, and limitations upon the release of NORM contaminated land for unrestricted use. We believe that our operations are in material compliance with all applicable NORM standards established by the states, as applicable.
OSHA and Other Laws and Regulations.
We are subject to the requirements of the federal Occupational Safety and Health Act (OSHA),Administration (“OSHA”) and comparable state laws. Thestatutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community right-to-knowEmergency Planning and Community Right-to-Know Act and comparable state statutes and any implementing regulations under the Title III of CERCLA and similar state laws require that we organize and/or disclose information about hazardous materials used or produced in our operations. Also, pursuantoperations and that this information be provided to OSHA, the Occupational Safetyemployees, state and Health Administration has established a variety of standards related to workplace exposure to hazardous substanceslocal governmental authorities and employee health and safety.citizens.
Taxation.Related Permits and Authorizations Our oil and gas operations are affected by
Many environmental laws require us to obtain permits or other authorizations from state and/or federal income tax laws applicable to the petroleum industry. For U.S. income tax reporting purposes, intangibleagencies before initiating certain drilling, and development costs incurredconstruction, production, operation, or borne during the year are permitted to be deducted currently, rather than capitalized. As an independent producer, we are also entitled to a deduction for percentage depletion
with respect to the first 1,000 barrels per day of domestic crude oil (and/or equivalent units of domestic natural gas) produced, if such percentage depletion exceeds cost depletion. Generally, this deduction is computed based upon the lesser of 100% of the net income, or 15% of the gross income from a property, without reference to the basis in the property. The amount of the percentage depletion deduction so computed which may be deducted in any given year is limited to 65% of taxable income. Any percentage depletion deduction disallowed due to the 65% of taxable income test may be carried forward indefinitely.
Substantive changes to existing federal income tax laws have been proposed that, if adopted, would repeal many tax incentives and deductions that are currently used by U.S. oil and gas companies and would impose new taxes. The proposals include: repeal of the percentage depletion allowance forother oil and natural gas properties; eliminationactivities 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 abilitywell 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 deduct intangible drilling costs in the year incurred; repeal of the manufacturing tax deduction for oil and gas companies; and increase in the geological and geophysical amortization period for independent producers. Should someinsured or all of these proposals become law, our taxes will increase, potentially significantly, which wouldindemnified against could have a negative impactmaterial adverse effect on our net incomefinancial condition and cash flows. This could also reduce our drilling activitiesoperations.
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 the U.S. Since none of these proposals have yet to become law,connection with complying with environmental laws or environmental remediation matters in 2023, nor do we do not know the ultimate impact these proposed changes may have on our business.anticipate that such expenditures will be material in 2024.
See Notes 1 and 9 to the consolidated financial statements included in this Report for a discussion of accounting for income taxes.
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 Company also faces competition from companies that supply alternative sources of energy, such as wind, solar and other renewables. Competition will increase as alternative energy technology becomes more reliable and governments throughout the world support or mandate the use of such alternative energy,
The availability of a ready market for any oil and gas produced by us at acceptable prices per unit of production will depend upon numerous factors beyond our control, including the extent of domestic production and importation of oil and gas, the proximity of our producing properties to gas pipelines and the availability and capacity of such pipelines, the marketing of other competitive fuels, fluctuation in demand, governmental regulation of production, refining, transportation and sales, general national and worldwide economic conditions, and use and allocation of oil and gas and their substitute fuels. There is no assurance that we will be able to market all of the oil or gas produced by us or that favorable prices can be obtained for the oil and gas production.
We derive our revenue and cash flow principally from the sale of oil, natural gas and NGLs. As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil, natural gas and NGLs. We sell our oil and natural gas on the open market at prevailing market prices or through forward delivery contracts. Because some of our operations are located outside major markets, we are directly impacted by regional prices regardless of Henry Hub, WTI or other major market pricing. The market price for oil, natural gas and NGLs is dictated by supply and demand; consequently, we cannot accurately predict or control the price we may receive for our oil, natural gas and NGLs.
We have an active hedging program to mitigate risk regarding our cash flow and to protect returns from our development activity in the event of decreases in the prices received for our production; however, hedging arrangements may expose us to risk of financial loss in some circumstances and may limit the benefit we would receive from increases in the prices for oil, natural gas and NGLs.
Oil and Gas Industry Considerations
The COVID-19 pandemic resulted in a severe worldwide economic downturn, significantly disrupting the demand for oil throughout the world, and created significant volatility, uncertainty and turmoil in the oil and gas industry. Since mid-2020, while oil prices have improved with demand steadily increasing, worldwide oil inventories, from a historical perspective, remain low. In addition, concerns exist with the ability of OPEC and other oil producing nations to meet forecasted future oil demand growth, with many OPEC countries not able to produce at their OPEC agreed upon quota levels due to their limited capital investments directed towards developing incremental oil supplies over the past few years. Furthermore, sanctions, import bans and price caps on Russia have been implemented by various countries in response to the war in Ukraine, further impacting global oil supply. As a result of these and other oil and gas supply constraints, the world has experienced significant increases in energy costs. In March 2024, OPEC announced a continuation of its 2.2 MMBOPD production cut that started in July 2023 related to the uncertainty surrounding the global economy and future oil demand. As a result of the global supply and demand imbalances experienced in 2023, oil and gas prices remained strong with average NYMEX oil and NYMEX gas prices for the three months ended December 31, 2023 being $78.41 per Bbl and $2.84 per Mcf, respectively, as compared to $82.79 per Bbl and $5.76 per Mcf, respectively, for the same period in 2022. In addition, economic volatility and geopolitical tensions have resulted in global supply chain disruptions, which has led to significant cost inflation. Global oil price levels and inflationary pressures will ultimately depend on various factors that are beyond the Company’s control, such as (i) the ability of OPEC and other oil producing nations to manage the global oil supply, (ii) the impact of sanctions and import bans on production from Russia, (iii) the timing and supply impact of any Iranian sanction relief on their ability to export oil, (iv) the global supply chain constraints associated with manufacturing and distribution delays, (v) oilfield service demand and cost inflation, and (vi) political stability of oil consuming countries and oil producing regions. The Company continues to assess and monitor the impact of these factors and consequences on the Company and its operations.
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 ourthe Company’s total oil and gas sales made to each of our customers whose purchaseswhich represented more than 10% of ourthe Company’s oil and gas sales in 2015.the year 2023.
Oil Purchasers: | ||||
APA Corporation | 22 | % | ||
Crivitas Resources Inc. | 20 | % | ||
Plains All American Inc. | % | |||
| % | |||
| ||||
Gas Purchasers: | ||||
| % | |||
Civitas Resources Inc. | 10 | % |
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 March 1, 2016,December 31, 2023, we had 180 full-time and 2 part-time115 full time employees, 2625 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, 10 employees in Stamford, Connecticut, and 14690 employees who were primarily involved in our district operations in HoustonMidland and Midland,Carrizo Springs, Texas, Elmore City and Oklahoma City, OklahomaOklahoma.
Item 1A. | RISK FACTORS |
General Risk Factors
The prices of oil, NGL and Charleston, West Virginia.
Natural gas and oil prices fluctuate widely, and low prices for an extended period of time are likely to have a material adverse impact on our business.
Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for natural gas and oil. Lower commodity prices may reduce the amount of natural gas and oil that we can produce economically. Natural gas prices, based on the twelve-month average of the first of the month Henry Hub index price, were $2.59$2.637 per MmbtuMMBTU in 20152023 as compared to $4.35$6.358 per MmbtuMMBTU in 2014,2022, and have continued to decline to $2.19averaged $2.446 per Mmbtu in February 2016.MMBTU for the first three months of 2024. Oil prices, based on West Texas Intermediate(WTI) Light Sweet Crude first of the NYMEX monthly average price, were $50.28month prices, averaged $78.22 per barrel in 20152023 as compared to $94.99$93.67 per barrel in 2014,2022, and have continued to decline to $31.78 in January 2016. Lower prices throughout 2015 have had, and anythe first three months of 2024, the first of the month price has averaged $77.48 per barrel.
Any substantial or extended decline in future natural gas or crude oil prices would have a material adverse effect on our future business, financial condition, results of operations, cash flows, liquidity or ability to finance planned capital expenditures and commitments. Furthermore, substantial, extended decreases in natural gas and crude oil prices may cause us to delay or postpone a significant portion of our exploration, development and exploitation projects or may render such projects uneconomic, which may result in significant downward adjustments to our estimated proved reserves and could negatively impact our ability to borrow and cost of capital and our ability to access capital markets, increase our costs under our revolving credit facility, and limit our ability to execute aspects of our business plans.
Prices for natural gas and oil are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty and a variety of additional factors that are beyond our control. These factors include:
● | the level of consumer product demand; |
● | the domestic and foreign supply of natural gas and oil |
● | weather conditions and natural disasters; |
● | political conditions in natural gas and oil producing regions, including the Middle East, Russia, Africa and South America; |
● | actions by the members of the Organization of Petroleum Exporting Countries with respect to oil production levels and announcements of potential changes in such levels; |
● | the price levels and quantities of foreign imports to the United States; |
● | 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; |
● | conservation and environmental protection efforts, including activities by non-governmental organizations to restrict the exploration, development and production of natural gas and oil; |
● | overall economic conditions; and |
● | global or national health concerns, including the outbreak of pandemic or contagious disease. |
In addition, lower oil and natural gas prices may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our exploration or development activities are curtailed, full cost accounting rules may require us to write down, as a noncash charge to earnings, the carrying value of our oil and natural gas properties. Reductions in our reserves could also negatively impact the borrowing base under our revolving credit facility, which could further limit our liquidity and ability to conduct additional exploration and development activities.
Concerns over general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.
Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, the European, Asian and the United States financial markets have in the past contributed, and may in the future contribute, to economic uncertainty and diminished expectations for the global economy. In addition, ongoing conflict in Ukraine and the Middle East, Africathe occurrence or threat of terrorist attacks in the United States or other countries and South America;
financial condition. These factors and the volatile nature of the energy markets make it impossible to predict with any certainty the future prices of natural gas and oil. If natural gas and oil prices decline significantly for a sustained period of time, the lower prices may adversely affect our ability to make planned expenditures, raise additional capital or meet our financial obligations.
Financial difficulties encountered by our oil and natural gas purchasers, third-party operators or other third parties could decrease cash flow from operations and adversely affect our exploration and development activities.
We derive essentially all of our revenues from the sale of our oil, natural gas and NGLs to unaffiliated third-party purchasers, independent marketing companies and midstream companies. Any delays in payments from such purchasers caused by their financial difficulties, including those resulting from continued volatility in both credit and commodity markets, will have an immediate negative effect on our results of operations and cash flows.
Additionally, liquidity and cash flow problems encountered by our working interest co-owners or the third- party operators of our non-operated properties may prevent or delay the drilling of a well or the development of a project. Our working interest co-owners may be unwilling or unable to pay their share of the costs of projects as they become due. In the case of a working interest owner, we could be required to pay the working interest owner’s share of the project costs.
We have substantial capital requirements, and we may not be able to obtain needed financing on satisfactory terms, if at all.
We rely upon access to our revolving credit facility as a source of liquidity for any capital requirements not satisfied by cash flow from operations or other sources. Future challenges in the global financial system, including the capital markets, may adversely affect our business and our financial condition. Our ability to access the capital markets may be restricted at a time when we desire, or need, to raise capital, which could have an impact on our flexibility to react to changing economic and business conditions. Adverse economic and market conditions could adversely affect the collectability of our trade receivables and cause our commodity hedging counterparties to be unable to perform their obligations or to seek bankruptcy protection. Future challenges in the economy could also lead to reduced demand for natural gas which could have a negative impact on our revenues.
Our debt agreements also require compliance with covenants to maintain specified financial ratios. If the price that we receive for our natural gas and oil production further deteriorates from current levels or continues for an extended period, it could lead to further reduced revenues, cash flow and earnings, which in turn could lead to a default under those ratios. Because the calculations of the financial ratios are made as of certain dates, the financial ratios can fluctuate significantly from period to period. A prolonged period of decreased natural gas and oil prices or a further decline could further increase the risk of our inability to comply with covenants to maintain specified financial ratios. In order to provide a margin of comfort with regard to these financial covenants, we may seek to reduce our capital expenditure plan, sell non-strategic assets or opportunistically modify or increase our derivative instruments to the extent permitted under our debt agreements. In addition, we may seek to refinance or restructure all or a portion of our indebtedness. We cannot assure you that we will be able to successfully execute any of these strategies, and such strategies may be unavailable on favorable terms or not at all.
Negative public perception regarding us and/or our industry could have an adverse effect on our operations.
Negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about hydraulic fracturing, oil spills, GHG emissions, climate change or methane emissions and explosions of natural gas transmission lines, may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we need to conduct our operations to be withheld, delayed, or burdened by requirements that restrict our ability to profitably conduct our business. In addition, investors currently focused on the potential effectives of climate change may elect to shift some or all of their investments into non-fossil fuel energy related investments. Limitation of investments in and financings for fossil fuel energy could restrict the availability of capital, resulting in the restriction, delay, or cancellation of development and production activities.
We may not be insured against all of the operating risks to which we are exposed.
We maintain insurance coverage against certain, but not all, hazards that could arise from our operations. Such insurance is believed to be reasonable for the hazards and risks faced by us. We do not carry business interruption insurance. In addition, pollution and environmental risks are not fully insurable.
We maintain for our operations total excess liability insurance with limits of $20 million per occurrence and in the aggregate covering certain general liability and certain “sudden and accidental” environmental risks with a deductible of $100,000 per occurrence, subject to all terms, restrictions and sub-limits of the policies. We also maintain general liability insurance limits of $1 million per occurrence and $2 million in the aggregate.
We have several policies that cover environmental risks. We have environmental coverage under the per occurrence and aggregate limits of our general and umbrella liability policies (for a twelve-month term). These policies provide third-party surface cleanup, bodily injury and property damage coverage, and defense costs when a pollution event is sudden and accidental and is discovered within thirty days of commencement and reported to the insurance company within ninety days of discovery. This is standard coverage in oil and gas insurance policies.
We seek to protect ourselves from some but not all operating hazards through insurance coverage. However, some risks are either not insurable or insurance is available only at rates that we consider uneconomical. Depending on competitive conditions and other factors, we attempt to obtain contractual protection against uninsured operating risks from our customers and contractors. However, customers and contractors who provide contractual indemnification protection may not in all cases maintain adequate insurance to support their indemnification obligations. Our insurance or indemnification arrangements may not adequately protect us against liability or loss from all the hazards of our operations. The occurrence of a significant event that we have not fully insured or indemnified against or the failure of a customer to meet its indemnification obligations to us could materially and adversely affect our results of operations and financial condition. Furthermore, we may not be able to maintain adequate insurance in the future at rates we consider reasonable.
From time to time, a small number of our contractors have requested contractual provisions that require us to respond to third-party claims. In some of these instances we have accepted the risk with the understanding that it would be covered under our current coverage. We evaluate these risk-transferring negotiations cautiously, and we feel that we have adequately mitigated this risk through existing coverage or acquiring supplemental coverage when appropriate.
Terrorist activities and the potential for military and other actions could adversely affect our business.
The threat of terrorism and the impact of military and other action have caused instability in world financial markets and could lead to increased volatility in prices for natural gas and oil, all of which could adversely affect the markets for our operations. Future acts of terrorism could be directed against companies operating in the United States. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of terrorist organizations. These developments have subjected our operations to increased risk and, depending on their ultimate magnitude, could have a material adverse effect on our business.
Our ability to sell our natural gas and oil production could be materially harmed if we fail to obtain adequate services such as transportation and processing.
The sale of our natural gas and oil production depends on a number of factors beyond our control, including the availability and capacity of transportation and processing facilities. If there were insufficient capacity available on these facilities, if these facilities were unavailable to the Company or if access to these facilities were to become commercially unreasonable, the price offered for the Company's production could be significantly depressed, or the Company could be forced to shut in some production or delay or discontinue drilling plans and commercial production following a discovery of hydrocarbons while it constructs its own facility or awaits the availability of third party facilities. The Company also relies (and expects to rely in the future) on facilities developed and owned by third parties in order to gather, store, process, transport, fractionate, refine, export and sell its oil, NGL and gas production. The Company's plans to develop and sell production from its oil and gas reserves could be materially and adversely affected by the inability or unwillingness of third parties to provide sufficient gathering, transportation, storage, processing, fractionation, refining or export facilities to the Company, especially in areas of planned expansion where such facilities do not currently exist. Our failure to obtain these services on acceptable terms could materially harm our business.
Competition in our industry is intense, and many of our competitors have substantially greater financial and technological resources than we do, which could adversely affect our competitive position.
Competition in the natural gas and oil industry is intense. Major and independent natural gas and oil companies actively bid for desirable natural gas and oil properties, as well as for the equipment and labor required to operate and develop these properties. Our competitive position is affected by price, contract terms and quality of service, including pipeline connection times, distribution efficiencies and reliable delivery record. Many of our competitors have financial and technological resources and exploration and development budgets that are substantially greater than ours. These companies may be able to pay more for exploratory projects and productive natural gas and oil properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may be able to expend greater resources on the existing and changing technologies that we believe are and will be increasingly important to attaining success in the industry.
The loss of key personnel could adversely affect our ability to operate.
Our operations are dependent upon a relatively small group of key management and technical personnel, and one or more of these individuals could leave our employment. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on us. In addition, our drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers and other professionals. Competition for experienced geologists, engineers and some other professionals is intense. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be harmed.
A failure of technology systems, data breach or cyber incident could materially affect our operations.
Our information technology systems may be vulnerable to security breaches, including those involving cyberattacks using viruses, worms or other destructive software, process breakdowns, phishing or other malicious activities, or any combination of the foregoing. Such breaches could result in unauthorized access to information, including customer, employee, or other confidential data. We do not carry insurance against these risks, although we do invest in security technology, perform penetration tests, and design our business processes to attempt to mitigate the risk of such breaches. However, there can be no assurance that security breaches will not occur. Moreover, cyber and other security threats are constantly evolving, thereby making it more difficult to successfully defend against them or to implement adequate preventative measures. The development and maintenance of these measures requires continuous monitoring as technologies change and security measures evolve. We have experienced, and expect to continue to experience, cyber threats and incidents, none of which has been material to us to date. However, a successful breach or attack could have a material negative impact on our operations or business reputation and subject us to consequences such as litigation and direct costs associated with incident response.
Information technology solution failures, network disruptions, breaches of data security and cyberattacks could disrupt our operations by causing delays, impeding processing of transactions and reporting financial results, resulting in the unintentional disclosure of customer, employee or our information, or damage to our reputation. A system failure, data security breach or cyberattack could have a material adverse effect on our financial condition, results of operations or cash flows. In the past, we have experienced data security breaches resulting from unauthorized access to our e-mail systems, which to date have not had a material impact on our business; however, there is no assurance that such impacts will not be material in the future.
In addition to the risks presented to our systems and networks, cyber attacks affecting oil and natural gas distribution systems maintained by third parties, or the networks and infrastructure on which they rely, could delay or prevent delivery of our production to markets. Further, cyber attacks on a communications network or power grid could cause operational disruption resulting in loss of revenues. A cyber attack of this nature would be outside our control, but could have a material, adverse effect on our business, financial condition and results of operations.
Risks Related to our Business
The shut-in of our wells could negatively impact our production, liquidity, and, ultimately, our operations, results, and performance.
Our production depends, in part, upon our wells that are capable of commercial production not being shut-in (i.e., suspended from production). The lack of availability of capacity on third-party systems and facilities or the shut-in of an oil field’s production could result in the shut-in of our wells.
The producing wells in which we have an interest occasionally experience reduced or terminated production. These curtailments can result from mechanical failures, contract terms, pipeline and processing plant interruptions, market conditions, operator priorities, and weather conditions. These curtailments can last from a few days to many months, any of which could have an adverse effect on our results of operations.
If we experience low oil production volumes due to the shut-in of our wells or other mechanical failures or interruptions, it would impact our ability to generate cash flows from operations and we could experience a reduction in our available liquidity. A decrease in our liquidity could adversely affect our ability to meet our anticipated working capital, debt service, and other liquidity needs.
Drilling natural gas and oil wells is a high-risk activity.
Our growth is materially dependent upon the success of our drilling program. Drilling for natural gas and oil involves numerous risks, including the risk that no commercially productive natural gas or oil reservoirs will be encountered. The cost of drilling, completing and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors beyond our control, including:
● | decreases in natural gas and oil prices; |
● | unexpected drilling conditions, pressure or irregularities in formations; |
● | equipment failures or accidents; |
● | adverse weather conditions; |
● | loss of title or other title related issues; |
● | surface access restrictions; |
● | lack of available gathering or processing facilities or delays in the construction thereof; |
● | lack of available capacity on interconnecting transmission pipelines; |
● | lack of available drilling and production equipment or availability of oil field labor; |
● | compliance with, or changes in, governmental requirements and regulation, including with respect to wastewater disposal, discharge of GHGs and fracturing; and |
● | shortages or delays in the availability of required goods or services such as drilling rigs or crews, the delivery of equipment and the availability of sufficient water for drilling operations. |
Our future drilling activities may not be successful and, if unsuccessful, such failure will have an adverse effect on our future results of operations and financial condition. Our overall drilling success rate or our drilling success rate within a particular geographic area may decline. We may be unable to lease or drill identified or budgeted prospects within our expected time frame, or at all. We may be unable to lease or drill a particular prospect because, in some cases, we identify a prospect or drilling location before seeking an option or lease rights in the prospect or location. Similarly, our drilling schedule may vary from our capital budget. The final determination with respect to the drilling of any scheduled or budgeted wells will be dependent on a number of factors, including:
● | the results of exploration efforts and the acquisition, review and analysis of the seismic data; |
● | the availability of sufficient capital resources to us and the other participants for the drilling of the prospects; |
● | the approval of the prospects by other participants after additional data has been compiled; |
● | economic and industry conditions at the time of drilling, including prevailing and anticipated prices for natural gas and oil and the availability of drilling rigs and crews; |
● | our financial resources and results; and |
● | the availability of leases and permits on reasonable terms for the prospects. |
These projects may not be successfully developed and the wells, if drilled, may not encounter reservoirs of commercially productive natural gas or oil.
Reserve estimates depend on many assumptions that may prove to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated.
Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact manner. The process of estimating quantities of proved reserves is complex and inherently uncertain, and the reserve data included in this document are only estimates. The process relies on interpretations of available geologic, geophysical, engineering and production data. As a result, estimates of different engineers may vary. In addition, the extent, quality and reliability of this technical data can vary. The differences in the reserve estimation process are substantially due to the geological conditions in which the wells are drilled. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as natural gas and oil prices. Additional assumptions include drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserve estimate is a function of:
● | the quality and quantity of available data; |
● | the interpretation of that data; |
● | the accuracy of various mandated economic assumptions; and |
● | the judgment of the persons preparing the estimate. |
Results of drilling, testing and production subsequent to the date of an estimate may justify revising the original estimate. Accordingly, initial reserve estimates often vary from the quantities of natural gas and oil that are ultimately recovered, and such variances may be material. Any significant variance could reduce the estimated quantities and present value of our reserves.
You should not assume that the present value of future net cash flows from our proved reserves is the current market value of our estimated natural gas and oil reserves. In accordance with SEC requirements, we base the estimated discounted future net cash
flows from our proved reserves on the twelve-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first day of the month price for each month, and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor we use when calculating discounted future net cash flows for reporting requirements in compliance with the Financial Accounting Standards Board (“FASB”) in Accounting Standards Codification (“ASC”) Section 932 may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.
The Company’sCompany’s expectations for future drilling activities will be realized over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of such activities.
The Company has identified drilling locations and prospects for future drilling opportunities, including development and infill drilling activities. These drilling locations and prospects represent a significant part of the Company’s future drilling plans. The Company’s ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, negotiation of agreements with third parties, commodity prices, costs, access to and availability of equipment, services, resources and personnel and drilling results. Changes in the laws or regulations on which the Company relies in planning and executing its drilling programs could adversely impact the Company’s ability to successfully complete those programs. For example, under current Texas laws and regulations the Company may receive permits to drill, and may drill and complete, certain horizontal wells that traverse one or more units and/or leases; a change in those laws or regulations could adversely impact the Company’s ability to drill those wells. Because of these uncertainties, the Company cannot give any assurance as to the timing of these activities or that they will ultimately meet the Company’s expectations for success. As such, the Company’s actual drilling activities may materially differ from the Company’s current expectations, which could have a significant adverse effect on the Company’s proved reserves, financial condition and results of operations.
Our future performance depends on our ability to find or acquire additional natural gas and oil reserves that are economically recoverable.
In general, the production rate of natural gas and oil properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Unless we successfully replace the reserves that we produce, our reserves will decline, eventually resulting in a decrease in natural gas and oil production and lower revenues and cash flow from operations. Our future natural gas and oil production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves. We may not be able to replace reserves through our exploration, development and exploitation activities or by acquiring properties at acceptable costs. Low natural gas and oil prices may further limit the kinds of reserves that we can develop economically. Lower prices also decrease our cash flow and may cause us to decrease capital expenditures.
Exploration, development and exploitation activities involve numerous risks that may result in dry holes, the failure to produce natural gas and oil in commercial quantities and the inability to fully produce discovered reserves. In addition, there are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves, actual future production rates and associated costs and the assumption of potential liabilities with respect to prospective acquisition targets. Actual results may vary substantially from those assumed in the estimates.
We are continually identifying and evaluating opportunities to acquire natural gas and oil properties. We may not be able to successfully consummate any acquisition, to acquire producing natural gas and oil properties that contain economically recoverable reserves, or to integrate the properties into our operations profitably.
We have substantial capital requirements, and we may not be able to obtain needed financing on satisfactory terms, if at all.
We rely upon access to our revolving credit facility as a source of liquidity for any capital requirements not satisfied by cash flow from operations or other sources. Future challenges in the global financial system, including the capital markets, may adversely affect our business and our financial condition. Our ability to access the capital markets may be restricted at a time when we desire, or need, to raise capital, which could have an impact on our flexibility to react to changing economic and business conditions. Adverse economic and market conditions could adversely affect the collectability of our trade receivables and cause our commodity hedging counterparties to be unable to perform their obligations or to seek bankruptcy protection. Future challenges in the economy could also lead to reduced demand for natural gas which could have a negative impact on our revenues.
Our debt agreements also require compliance with covenants to maintain specified financial ratios. If the price that we receive for our natural gas and oil production further deteriorates from current levels or continues for an extended period, it could lead to further reduced revenues, cash flow and earnings, which in turn could lead to a default under those ratios. Because the calculations of the financial ratios are made as of certain dates, the financial ratios can fluctuate significantly from period to period. A prolonged period of decreased natural gas and oil prices or a further decline could further increase the risk of our inability to comply with covenants to maintain specified financial ratios. In order to provide a margin of comfort with regard to these financial covenants, we
may seek to reduce our capital expenditure plan, sell non-strategic assets or opportunistically modify or increase our derivative instruments to the extent permitted under our debt agreements. In addition, we may seek to refinance or restructure all or a portion of our indebtedness. We cannot assure you that we will be able to successfully execute any of these strategies, and such strategies may be unavailable on favorable terms or not at all.
The borrowing base under our revolving credit facility may be reduced in light of recent commodity price declines, which could limit us in the future.
The borrowing base under our revolving credit facility is currently $95$85 million, and lender commitments under our revolving credit facility are $250$300 million. The borrowing base is redetermined semi-annually under the terms of the revolving credit facility. In addition, either we or the lenders may request an interim redetermination twice a year or in conjunction with certain acquisitions or sales of oil and gas properties. Our borrowing base may decrease as a result of lower natural gas or oil prices, operating difficulties, declines in reserves, lending requirements or regulations, the issuance of new indebtedness or for other reasons set forth in our revolving credit agreement. In the event of a decrease in our borrowing base due to declines in commodity prices or otherwise, our ability to borrow under our revolving credit facility may be limited and we could be required to repay any indebtedness in excess of the redetermined borrowing base. In addition, we may be unable to access the equity or debt capital markets to meet our obligations, including any such debt repayment obligations.
Strategic determinations, including the allocation of capital and other resources to strategic opportunities, are challenging, and our failure to appropriately allocate capital and resources among our strategic opportunities may adversely affect our financial condition and reduce our growth rate.
Our future growth prospects are dependent upon our ability to identify optimal strategies for our business. In developing our business plan, we considered allocating capital and other resources to various aspects of our businesses including well-development (primarily drilling), reserve acquisitions, exploratory activity, corporate items and other alternatives. We also considered our likely sources of capital. Notwithstanding the determinations made in the development of our 20162024 plan, business opportunities not previously identified periodically come to our attention, including possible acquisitions and dispositions. If we fail to identify optimal business strategies, or fail to optimize our capital investment and capital raising opportunities and the use of our other resources in furtherance of our business strategies, our financial condition and growth rate may be adversely affected. Moreover, economic or other circumstances may change from those contemplated by our 20162024 plan, and our failure to recognize or respond to those changes may limit our ability to achieve our objectives.
Negative public perception regarding us and/or our industry could have an adverse effect on our operations.
Negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about hydraulic fracturing, oil spills, greenhouse gas or methane emissions and explosions of natural gas transmission lines, may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we need to conduct our operations to be withheld, delayed, or burdened by requirements that restrict our ability to profitably conduct our business.
We face a variety of hazards and risks that could cause substantial financial losses.
Our business involves a variety of operating risks, including:
● | blowouts, cratering and explosions; |
● | mechanical problems; |
● | uncontrolled flows of natural gas, oil or well fluids; |
● | formations with abnormal pressures; |
● | pollution and other environmental risks; and |
● | natural disasters. |
Our operation of natural gas gathering and pipeline systems also involves various risks, including the risk of explosions and environmental hazards caused by pipeline leaks and ruptures. Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to the Company due to injury or loss of life, damage to or destruction of wells, production facilities, other property or natural resources, clean-up responsibilities, regulatory investigations and penalties and suspension of operations.
We may not be insured against allThe nature of the operating risksCompany’s assets and production operations may impact the environment or cause environmental contamination, which could result in material liabilities to which we are exposed.the Company.
We maintain insurance coverage against certain, but not all,
The Company’s assets and production operations may give rise to significant environmental costs and liabilities as a result of the Company’s handling of petroleum hydrocarbons and wastes, because of air emissions and water discharges related to its operations, and due to past industry operations and waste disposal practices. The Company’s oil and gas business involves the generation, handling, treatment, storage, transport and disposal of wastes, hazardous substances and petroleum hydrocarbons and is subject to environmental hazards, such as oil and produced water spills, NGL and gas leaks, pipeline and vessel ruptures and unauthorized discharges of such wastes, substances and hydrocarbons, that could arise from our operations. Such insurance is believedexpose the Company to be reasonable for the hazards and risks faced by us. We do not carry business interruption insurance. In additionsubstantial liability due to pollution and other environmental risksdamage. For example, drilling fluids, produced waters and certain other wastes associated with the Company’s exploration, development and production of oil or gas are not fully insurable. The occurrencecurrently excluded under RCRA from the definition of an event not fully covered by insurancehazardous waste. These wastes are instead regulated under RCRA’s less stringent non-hazardous waste provisions. There have been efforts from time to time to remove this exclusion. For example, in response to a federal consent decree issued in 2016, the EPA was required during 2019 to determine whether certain Subtitle D criteria regulations required revision in a manner that could result in oil and gas wastes being regulated as RCRA hazardous waste. In April 2019, the EPA made a determination that such revision of the regulations was unnecessary. Any future loss of the RCRA exclusion could have a material adverse effect on our financial position, results of operations and cash flows.
As of December 31, 2015, we maintain for our operations total excess liability insurance with limits of $20 million per occurrence and in the aggregate covering certain general liability and certain “sudden and accidental” environmental risks with a deductible of $10,000 per occurrence, subject to all terms, restrictions and sub-limits of the policies. We also maintain general liability insurance limits of $1 million per occurrence and $2 million in the aggregate.
We have several policies that cover environmental risks. We have environmental coverage under the per occurrence and aggregate limits of our general and umbrella liability policies (for a twelve-month term). These policies provide third-party surface cleanup, bodily injury and property damage coverage, and defense costs when a pollution event is sudden and accidental and is discovered within thirty days of commencement and reported to the insurance company within ninety days of discovery. This is standard coverage in oil and gas insurance policies.
We seek to protect ourselves from some but not all operating hazards through insurance coverage. However, some risks are either not insurable or insurance is available only at rates that we consider uneconomical. Depending on competitive conditions and other factors, we attempt to obtain contractual protection against uninsured operating risks from our customers and contractors. However, customers and contractors who provide contractual indemnification protection may not in all cases maintain adequate insurance to support their indemnification obligations. Our insurance or indemnification arrangements may not adequately protect us against liability or loss from all the hazards of our operations. The occurrence of a significant event that we have not fully insured or indemnified against or the failure of a customer to meet its indemnification obligations to us could materially and adversely affect ourCompany’s results of operations and financial condition. Furthermore, we may not be able to maintain adequate insuranceposition.
The Company currently owns, leases or operates, and in the future at rates we consider reasonable.
From time to time, a small number of our contractorspast has owned, leased or operated, properties that for many years have requested contractual provisions that require us to respond to third-party claims. In some of these instances we have accepted the risk with the understanding that it would be covered under our current coverage. We evaluate these risk-transferring negotiations cautiously, and we feel that we have adequately mitigated this risk through existing coverage or acquiring supplemental coverage when appropriate.
Federal and state legislation and regulatory initiatives related tobeen used for oil and gas development, including hydraulic fracturing, could result in increased costs and operating restrictions or delays.
Most of our exploration and production activities, and petroleum hydrocarbons, hazardous substances and wastes may have been released on or under such properties, or on or under other locations, including off-site locations, where such substances have been taken for treatment or disposal. These wastes, substances and hydrocarbons may also be released during future operations. In addition, some of the Company’s properties have been operated by predecessors or previous owners or operators whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons were not under the Company’s control. Joint and several strict liabilities may be incurred in connection with such releases of petroleum hydrocarbons, hazardous substances and wastes on, under or from the Company’s properties. Private parties, including lessors of properties on which the Company operates and the owners or operators of properties adjacent to the Company’s operations depend onand facilities where the use of hydraulic fracturingCompany’s petroleum hydrocarbons, hazardous substances or wastes are taken for reclamation or disposal, may also have the right to enhance production from oil and gas wells. This technology involves the injection of fluids—usually consisting mostly of water but typically including small amounts of several chemical additives—pursue legal actions to enforce compliance as well as sandseek damages for noncompliance with environmental laws and regulations or other proppants into a wellfor personal injury or damage to property or natural resources. Such properties and the substances disposed or released on or under high pressure in order to create fractures in the rock that allow oil or gas to flow more freely to the wellbore. Most of our wells would not be economical without the use of hydraulic fracturing to stimulate production from the well. Hydraulic fracturing operations have historically been overseen by state regulators as part of their oil and gas regulatory programs; however, the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the Safe Drinking Water Act and has released permitting guidance for hydraulic fracturing activities that use diesel in fracturing fluids in those states where EPA is the permitting authority, including Pennsylvania. As a result, wethem may be subject to additional permitting requirements for hydraulic fracturing operations as well as various restrictions on those operations. These permitting requirementsCERCLA, RCRA and restrictionsanalogous state laws, which could result in delays in operations at well sites as well as increased costs to make wells productive. In addition, legislation introduced in Congress would provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and require the public disclosure of certain information regarding the chemical makeup of hydraulic fracturing fluids. If adopted, this legislation could establish an additional level of regulationCompany to remove previously disposed substances, wastes and permitting at the federal, statepetroleum hydrocarbons, remediate contaminated property or local levels, and could make it easier for third parties opposed to the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect the environment, including groundwater, soilperform remedial plugging or surface water. Moreover, in May 2014, the EPA announced an Advanced Notice of Proposed Rulemaking under the Toxic Substances Control Act relating to data collection, including the chemical substances and mixtures used in hydraulic fracturing. Further, in March 2015, the Department of the Interior’s Bureau of Land Management (BLM) issued a final rule to regulate hydraulic fracturing on public and Indian land; however, enforcement of the rule has been delayed pending a decision in a legal challenge in the U.S. District Court of Wyoming.
On August 16, 2012, the EPA published final rules that establish new air emission control requirements for natural gas and NGL production, processing and transportation activities, including New Source Performance Standards (NSPS) to address emissions of sulfur dioxide and volatile organic compounds, and National Emission Standards for Hazardous Air Pollutants (NESHAPS) to address hazardous air pollutants frequently associated with gas production and processing activities. Among other things, these final rules require the reduction of volatile organic compound emissions from natural gas wells through the use of reduced emission completions or “green completions” on all hydraulically fractured wells constructed or refractured after January 1, 2015. In addition, gas wells were required to use completion combustion device equipment (i.e., flaring) if emissions cannot be directed to a gathering line. Further, the final rules under NESHAPS include maximum achievable control technology (MACT) standards for “small” glycol dehydrators that are located at major sources of hazardous air pollutants and modifications to the leak detection standards for valves. In December 2014, the EPA finalized additional amendments to these rules that, among other things, distinguished between multiple flowback stages during completion and clarified that storage tanks permanently removed from service are not affected by any requirements. In July 2015, the EPA finalized two updates to the rules addressing the definition of low pressure gas wells and references to tanks that are connected to one another. In September 2015, the EPA issued a proposed rule that would update and expand the NSPS by setting additional emissions limits for volatile organic compounds and regulating methane emissions for new and modified sources in the oil and gas industry. The EPA also issued a proposed rule in September 2015 concerning aggregation of sources that would affect source determinations for air permitting in the oil and gas industry.
Compliance with these requirements, especially the imposition of these green completion requirements and potential methane regulation, may require modifications to certain of our operations, including the installation of new equipment to control emissions at the well site that could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business. Similarly, aggregating our oil and gas facilities for permitting could result in more complex, costly, and time consuming air permitting. Particularly in regard to obtaining pre-construction permits, the proposed aggregation rule could add costs and cause delays in our operations.
In addition to these federal legislative and regulatory proposals, some states in which we operate, such as West Virginia and Texas, and certain local governments have adopted, and others are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances, including requirements regarding chemical disclosure, casing and cementing of wells, withdrawal of water for use in high-volume hydraulic fracturing of horizontal wells, baseline testing of nearby water wells, and restrictions on the type of additives that may be used in hydraulic fracturing operations. For example, the City of Denton, Texas adopted a moratorium on hydraulic fracturing in November 2014, though it was later lifted in 2015, and New York issued a statewide ban on hydraulic fracturing in June 2015. In addition, Pennsylvania’s Act 13 of 2012 became law on February 14, 2012 and amended the state’s Oil and Gas Act to, among other things, increase civil penalties and strengthen the Pennsylvania Department of Environmental Protection’s (PaDEP) authority over the issuance of drilling permits. Although the Pennsylvania Supreme Court struck down portions of Act 13 that made statewide rules on oil and gas preempt local zoning rules, this could lead to additional local restrictions on oil and gas activity in the state. Additional challenges to Act 13 are pending before the Pennsylvania Supreme Court; however, the timing of any decision is uncertain.
We use a significant amount of water in our hydraulic fracturing operations. Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our operations, could adversely impact our operations. Moreover, new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of natural gas. Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted, all of which could have an adverse effect on our operations and financial condition. For example, in April 2011, PaDEP called on all Marcellus Shale natural gas drilling operators to voluntarily cease by May 19, 2011 delivering wastewater to those centralized treatment facilities that were grandfathered from the application of PaDEP’s Total Dissolved Solids regulations. In April 2015, the EPA published proposed pretreatment standards for disposal of wastewater produced from shale gaspit closure operations to publicly owned treatment works (POTWs). The regulations will be developed under the EPA’s Effluent Guidelines Program under the authority of the Clean Water Act. In response to these actions, operators including us have begun to rely more on recycling of flowback and produced water from well sites as a preferred alternative to disposal.
A number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing practices. The EPA is conducting a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater. The EPA released a draft report in June 2015. It concluded that activities have not led to widespread systematic impacts on drinking water resources in the United States, but there are above and below ground mechanisms by which hydraulic fracturing could affect drinking water resources. This study and other studies that may be undertaken by EPA or other federal agencies could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act, the Toxic Substances Control Act, or other statutory and/or regulatory mechanisms.
Climate change and climate change legislation and regulatory initiatives could result in increased operating costs and decreased demand for the oil and natural gas that we produce.
Climate change,prevent future contamination, the costs that may be associated with its effects, and the regulation of greenhouse gas (GHG) emissions have the potential to affect our business in many ways, including increasing the costs to provide our products and services, reducing the demand for and consumption of our products and services (due to change in both costs and weather patterns), and the economic health of the regions in which we operate, all of which can create financial risks. In addition, legislative and regulatory responses related to GHG emissions and climate change may increase our operating costs. The United States Congress has previously considered legislation related to GHG emissions. There have also been international efforts seeking legally binding reductions in GHG emissions. For example, in November 2014, the Obama Administration announced an agreement with China to voluntarily reduce GHG emissions by 26% to 28% of 2005 levels by 2025. Further, the United States joined over 190 countries in Lima, Peru in December 2014 and agreed to draft an emissions reduction plan ahead of further international climate negotiations in Paris, France in 2015. The United States was actively involved in the negotiations in Paris, which led to the creation of the Paris Agreement. The Paris Agreement will be open for signing on April 22, 2016 and will require countries to review and “represent a progression” in their intended nationally determined contributions, which set emissions reduction goals, every five years, beginning in 2020. The Paris Agreement sets a goal of keeping warming well below 2 degrees Celsius and sets a target limit of 1.5 degrees Celsius. In addition, increased public awareness and concern may result in more state, regional and/or federal requirements to reduce or mitigate GHG emissions. For example, in June 2013, the Obama Administration announced its Climate Action Plan, which, among other things, directs federal agencies to develop a strategy for the reduction of methane emissions, including emissions from the oil and gas sector. Pursuant to this plan, the EPA issued a proposed rule updating New Source Performance Standards and setting requirements for methane emissions and volatile organic compounds in the oil and gas sector in September 2015.
In September 2009, the EPA finalized a mandatory GHG reporting rule that requires large sources of GHG emissions to monitor, maintain records on, and annually report their GHG emissions beginning January 1, 2010. The rule applies to large facilities emitting 25,000 metric tons or more of carbon dioxide-equivalent (CO2e) emissions per year and to most upstream suppliers of fossil fuels, as well as manufacturers of vehicles and engines. Subsequently, in November 2010, the EPA issued GHG monitoring and reporting regulations that went into effect on December 30, 2010, specifically for oil and natural gas facilities, including onshore and offshore oil and natural gas production facilities that emit 25,000 metric tons or more of CO2e per year. The rule required reporting of GHG emissions by regulated facilities to the EPA by March 2012 for emissions during 2011 and annually thereafter. We are required to report our GHG emissions to the EPA each year in March under this rule and have submitted our annual reports in compliance with the deadline. The EPA also issued a final rule that makes certain stationary sources and newer modification projects subject to permitting requirements for GHG emissions, beginning in 2011, under the CAA. However, in June 2014, the U.S. Supreme Court, in UARG v. EPA, limited the application of the GHG permitting requirements under the Prevention of Significant Deterioration and Title V permitting programs to sources that would otherwise need permits based on the emission of conventional pollutants.
Federal and state regulatory agencies can impose administrative, civil and/or criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. In addition, the passage of any federal or state climate change laws or regulations in the future could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities and (iii) administer and manage any GHG emissions program. If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on ourthe Company’s business, financial condition and results of operations and financial condition. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our costoperations.
The Company may not be able to recover some or any of and access to capital. Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competingthese costs from sources of energy.contractual indemnity or insurance, as pollution and similar environmental risks generally are not insurable or fully insurable, either because such insurance is not available or because of the high premium costs and deductibles associated with obtaining such insurance.
Moreover, some experts believe climate change poses potential physical risks, including an increase in sea level and changes in weather conditions, such as an increase in changes in precipitation and extreme weather events. In addition, warmer winters as a result of global warming could also decrease demand for natural gas. To the extent that such unfavorable weather conditions are exacerbated by global climate change or otherwise, our operations may be adversely affected to a greater degree than we have previously experienced, including increased delays and costs. However, the uncertain nature of changes in extreme weather events (such as increased frequency, duration, and severity) and the long period of time over which any changes would take place make any estimations of future financial risk to our operations caused by these potential physical risks of climate change unreliable.
We have limited control over the activities on properties we do not operate.
Other companies operate some of the properties in which we have an interest. We have limited ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund with respect to them. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interest could reduce our production and revenues. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.
Terrorist activities and the potential for military and other actions could adversely affect our business.
The threat of terrorism and the impact of military and other action have caused instability in world financial markets and could lead to increased volatility in prices for natural gas and oil, all of which could adversely affect the markets for our operations. Future acts of terrorism could be directed against companies operating in the United States. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of terrorist organizations. These developments have subjected our operations to increased risk and, depending on their ultimate magnitude, could have a material adverse effect on our business.
Our ability to sell our natural gas and oil production could be materially harmed if we fail to obtain adequate services such as transportation and processing.
The sale of our natural gas and oil production depends on a number of factors beyond our control, including the availability and capacity of transportation and processing facilities. Our failure to obtain these services on acceptable terms could materially harm our business.
Competition in our industry is intense, and many of our competitors have substantially greater financial and technological resources than we do, which could adversely affect our competitive position.
Competition in the natural gas and oil industry is intense. Major and independent natural gas and oil companies actively bid for desirable natural gas and oil properties, as well as for the equipment and labor required to operate and develop these properties. Our competitive position is affected by price, contract terms and quality of service, including pipeline connection times, distribution efficiencies and reliable delivery record. Many of our competitors have financial and technological resources and exploration and development budgets that are substantially greater than ours. These companies may be able to pay more for exploratory projects and productive natural gas and oil properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may be able to expend greater resources on the existing and changing technologies that we believe are and will be increasingly important to attaining success in the industry.
We may have hedging arrangements that expose us to risk of financial loss and limit the benefit to us of increases in prices for natural gas and oil.
From time to time, when we believe that market conditions are favorable, we use certain derivative financial instruments to manage price risks associated with our production in all of our regions. These hedging arrangements limit the benefit to us of increases in prices. While there are many different types of derivatives available, we generally utilize collarput options and swap agreements to attempt to manage price risk more effectively.
The collar arrangements are put and call options used to establish floor and ceiling prices for a fixed volume of production during a certain time period. They provide for payments to counterparties if the index price exceeds the ceiling and payments from the counterparties if the index price falls below the floor. The swap agreements call for payments to, or receipts from, counterparties based on whether the index price for the period is greater or less than the fixed price established for that period when the swap is put in place. These arrangements limit the benefit to us of increases in prices. In addition, these arrangements expose us to risks of financial loss in a variety of circumstances, including when:
● | a counterparty is unable to satisfy its obligations |
● | production is less than expected; or |
● | there is an adverse change in the expected differential between the underlying price in the derivative instrument and actual prices received for our production. |
The CFTC has promulgated regulations to implement statutory requirements for swap transactions. These regulations are intended to implement a regulated market in which most swaps are executed on registered exchanges or swap execution facilities and cleared through central counterparties. While we believe that our use of swap transactions exempt us from certain regulatory requirements, the changes to the swap market due to increased regulation could significantly increase the cost of entering into new swaps or maintaining existing swaps, materially alter the terms of new or existing swap transactions and/or reduce the availability of new or existing swaps. If we reduce our use of swaps as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable.
Legal and Regulatory Risks
Laws and regulations regarding hydraulic fracturing, as well as governmental reviews of such activities, could result in increased costs and additional operating restrictions, delays or cancellations and have a material adverse effect on the Company’s production.
Hydraulic fracturing is a common practice that is used to stimulate production of hydrocarbons from tight formations. The lossCompany conducts hydraulic fracturing in its drilling and completion programs. The process involves the injection of key personnelwater, sand or other proppants and additives under pressure into targeted subsurface formations to stimulate oil and gas production. The process is typically regulated by state oil and gas commissions or similar agencies, but in recent years, several federal agencies have conducted investigations or asserted regulatory authority over certain aspects of the process. For example, in 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances. Additionally, the EPA has asserted regulatory authority pursuant to the SDWA’s UIC program over hydraulic fracturing activities involving the use of diesel and has issued guidance covering such activities. Moreover, the EPA has published an Advance Notice of Proposed Rulemaking to collect data on chemicals used in hydraulic fracturing under the Toxic Substances Control Act and has implemented a final rule under the CWA prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly-owned wastewater treatment plants. Also, the BLM published a final rule in 2015 that established new or more stringent standards for performing hydraulic fracturing on federal and Indian lands. The BLM rescinded the 2015 rule in late 2017; however, new or more stringent regulations may be promulgated in the future.
From time to time, the U.S. Congress has considered adopting legislation intended to provide for federal regulation of hydraulic fracturing and to require disclosure of the additives used in the hydraulic-fracturing process. In addition, certain states, including Texas where the Company operates, have adopted, and other states are considering adopting, regulations that could adversely affect ourimpose new or more stringent permitting, disclosure, disposal and well-construction requirements on hydraulic-fracturing operations. For example, in April 2019, Colorado passed legislation reforming exploration and production activities by the oil and gas industry in the state including, among other things, revising the mission of the state oil and gas agency from fostering energy development in the state to instead focusing on regulating the industry in a manner that is protective of public health and safety and the environment, as well as authorizing cities and counties to regulate oil and gas operations within their jurisdictions as they do other development. While the Company does not conduct operations in Colorado, passage or enactment of similar legislation in other states in which it does operate could significantly increase the Company’s operating costs and have a significant adverse effect on the Company’s ability to operate.conduct operations. States could elect to prohibit hydraulic fracturing or high volume hydraulic fracturing altogether, following the approach taken by the states of Vermont, Maryland, Washington and New York. Also, local land use restrictions, such as city ordinances, may be adopted to restrict or prohibit drilling in general or hydraulic fracturing in particular. In Texas, legislation was adopted providing that the regulation of oil and gas operations in Texas is under the exclusive jurisdiction of the state and thus preempts local regulation of those operations. Nonetheless, municipalities and political subdivisions in Texas continue to have the right to enact “commercially reasonable” regulations for surface activities.
Our
In the event federal, state or local restrictions or bans pertaining to hydraulic fracturing are adopted in areas where the Company is currently conducting operations, are dependent upon a relatively small groupor in the future plans to conduct operations, the Company may incur additional costs to comply with such requirements, experience restrictions, delays or cancellations in the pursuit of key managementexploration, development or production activities, and technical personnel, andperhaps be limited or precluded in the drilling of wells or in the volume that the Company is ultimately able to produce from its reserves; one or more of which developments could have a material adverse effect on the Company.
The Company’s operations are subject to stringent environmental, oil and gas-related and occupational safety and health laws and regulations that could cause it to delay, curtail or cease its operations or expose it to material costs and liabilities.
The Company’s operations are subject to stringent federal, state and local laws and regulations governing, among other things, the drilling of wells, rates of production, the size and shape of drilling and spacing units or proration units, the transportation and sale of oil, NGL and gas, and the discharging of materials into the environment and environmental protection. For example, state laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and gas properties. Some states allow forced pooling or integration of tracts to facilitate development, while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce the Company’s interest in the unitized properties. In addition, state conservation laws (i) establish maximum rates of production from oil and gas wells, (ii) generally prohibit the venting or flaring of gas and (iii) impose requirements regarding production rates. These laws and regulations may limit the amount of oil and gas the Company can produce from the Company’s wells or limit the number of wells or the locations that the Company can drill.
In connection with its operations, the Company must obtain and maintain numerous environmental and oil and gas-related permits, approvals and certificates from various federal, state and local governmental authorities, and may incur substantial costs in doing so. The need to obtain permits has the potential to delay, curtail or cease the development of oil and gas projects. The Company may in the future be charged royalties on gas emissions or required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in 2015, the EPA issued a final rule under the CAA lowering the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone from 75 parts per billion to 70 parts per billion under standards to provide protection of public health and welfare. In subsequent years, the EPA has issued area designations with respect to ground-level ozone and final requirements that apply to state, local and tribal air agencies for implementing the 2015 NAAQS for ground-level ozone. State implementation of the revised NAAQS could, among other things, require installation of new emission controls on some of the Company’s equipment, resulting in longer permitting timelines, and significantly increase the Company’s capital expenditures and operating costs. In another example, the EPA and U.S. Army Corps of Engineers (the “Corps”) released a final rule in 2015 outlining federal jurisdictional reach under the CWA over waters of the U.S., including wetlands, which has since been subject to several revisions. In August 2023, the EPA finalized a rule amending the definition of “waters of the United States” to conform with the recent Supreme Court decision in Sackett v. EPA. However, litigation challenging aspects of the January 2023 definition not addressed by Sackett is ongoing. To the extent that future changes to the definition expand the scope of the CWA’s jurisdiction in areas where the Company conducts operations, the Company could incur (i) delays, restrictions or prohibitions in the issuance of necessary permits, (ii) restrictions or cessations in the development or expansion of projects, or (iii) increases in the Company’s capital expenditures and operating expenses by, for example, requiring installation of new emission controls on some of the Company’s equipment, any one or more of which developments could have a material adverse effect on the Company’s business, financial condition and results of operations.
Additionally, the Company’s operations are subject to a number of federal and state laws and regulations, including the federal OSHA and comparable state statutes, whose purpose is to protect the health and safety of employees. Among other things, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in the Company’s operations and that this information be provided to employees, state and local government authorities and citizens.
There can be no assurance that existing or future regulations will not result in a delay, curtailment or cessation of production or processing activities, result in a material increase in the costs of production, development, exploration or processing operations or materially and adversely affect the Company’s future operations and financial condition. Noncompliance with these individualslaws and regulations may subject the Company to sanctions, including administrative, civil or criminal penalties, remedial cleanups or corrective actions, delays in permitting or performance of projects, natural resource damages and other liabilities. Such laws and regulations may also affect the costs of acquisitions. In addition, these laws and regulations are subject to amendment or replacement in the future with more stringent legal requirements. Further, any delay, reduction or curtailment of the Company’s development and producing operations due to these laws and regulations could leave our employment. The unexpectedresult in the loss of acreage through lease expiration.
The Company’s operations are subject to a number of risks arising out of concerns regarding the threat of climate change, including regulatory, political, litigation and financial risks, that could result in increased operating costs and costs of compliance, limit the areas in which oil and gas production may occur, reduce demand for the oil and gas the Company produces, and expose the Company to the risk of increased activism and decreased funding for the industry, while the potential physical effects of climate change could disrupt the Company’s production and cause it to incur significant costs in preparing for or responding to those effects.
The threat of climate change continues to attract considerable attention in the United States and in foreign countries. Numerous initiatives have been proposed and are expected to continue to be proposed at the international, national, regional and state levels of government to monitor and limit existing sources of GHG emissions as well as to restrict or eliminate emissions from new sources. As a result, the Company’s operations are subject to a series of regulatory, political, litigation and financial risks associated with the production and processing of fossil fuels and emission of GHGs.
In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among other things, (i) establish construction and operating permit reviews for GHG emissions from certain large stationary sources, (ii) require the monitoring and annual reporting of GHG emissions from certain petroleum and gas system sources in the United States, (iii) implement CAA emission standards directing the reduction of methane from certain new, modified, or reconstructed facilities in the oil and gas sector, and (iv) together with the DOT, implement GHG emissions limits on vehicles manufactured for operation in the United States. For example, in December 2023, the EPA finalized NSPS Subpart OOOOb, which seeks to reduce methane and volatile organic compound emissions from the oil and natural gas source category and NSPS Subpart OOOOc, which create, for the first-time, emission guidelines for existing oil and natural gas sources that would be included in individual states’ implementation plans. These standards expand upon previously issued NSPS Subparts OOOO and OOOOa published by the EPA in 2012 and 2016, respectively. Additionally, various states, groups of states, and other countries have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, there is a non-binding agreement, the United Nations sponsored “Paris Agreement,” for nations to limit their GHG emissions through individually-determined reduction goals every five years after 2020. The United States withdrew from the Paris Agreement in November 2020 but reentered the agreement in February 2021. In April 2021, the Biden administration announced a new goal to reduce GHG emissions by 50% to 52% economy-wide by 2030 compared to 2005 levels. In August 2022, President Biden signed into law the Inflation Reduction Act, which created a methane emissions reduction program, provided significant funding to reduce emissions of methane from the oil and gas sector, and requires the EPA to impose a charge on certain oil and gas sources.
Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States. President Biden and the Democratic Party have identified climate change as a priority, and it is possible that additional executive orders and/or regulatory action targeting GHG emissions, or prohibiting or restricting oil and gas development activities in certain areas, will be proposed and/or promulgated during the Biden Administration. Litigation risks are also increasing, as a number of cities, local governments or other persons have sought to bring suit against oil and gas exploration and production companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those impacts.
There are also financial risks for fossil fuel producers as stockholders or bondholders currently invested in fossil-fuel energy companies concerned about the threat of climate change may elect in the future to shift some or all of their investments into non-fossil fuel energy related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. Additionally, investing and lending practices of various investment firms and institutional lenders have been the subject of intensive lobbying efforts in recent years, oftentimes public in nature, by environmental activists, proponents of the Paris Agreement, and foreign citizenry concerned about the threat of climate change not to provide funding for fossil fuel producers. For example, there have been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds, to divest of fossil fuel equities and lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities.
The adoption and implementation of new or more stringent international, federal or state regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from the oil and gas sector or otherwise restrict the areas in which this sector may produce oil and gas or generate GHG emissions could result in increased compliance and consumption costs, and thereby reduce demand for the oil and gas the Company produces. Additionally, political, litigation and financial risks could result in the restriction or cancellation of production activities, incurring liability for infrastructure damages as a result of climate change, or impairing the Company’s ability to continue to operate in an economic manner. Finally, if increasing concentrations of GHGs in the Earth’s atmosphere were to result in significant physical effects, such as increased frequency and severity of storms, floods, droughts and other extreme climatic events, then such effects could have a material adverse effect on the Company’s exploration and production operations.
In addition, companies in the oil and gas industry have been the target of activist efforts from both individuals and non-governmental organizations, including instituting litigation and supporting political or regulatory efforts to, among other things, limit or ban hydraulic fracturing, restrict or ban certain operating practices, including the disposal of waste materials, such as hydraulic fracturing fluids and produced water, deny or delay drilling permits, prohibit the venting or flaring of gas, reduce access of the oil and gas industry to federal and state government lands, and delay or cancel oil and gas developmental or expansion projects. The Company may need to incur significant costs associated with responding to these initiatives, and complying with any resulting additional legal or regulatory requirements could have a material adverse effect on the Company’s business, financial condition, cash flows and results of operations.
Laws and regulations pertaining to protection of threatened and endangered species or to critical habitat, wetlands and natural resources could delay, restrict or prohibit the Company’s operations and cause it to incur substantial costs that may have a material adverse effect on the Company’s development and production of reserves.
The federal ESA and comparable state laws were established to protect endangered and threatened species. Under the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Federal Migratory Bird Treaty Act. Oil and gas operations in the Company’s operating areas may be adversely affected by seasonal or permanent restrictions imposed on drilling activities by the U.S. Fish and Wildlife Services (the “FWS”) that are designed to protect various wildlife, which may materially restrict the Company’s access to federal or private land use. Permanent restrictions imposed to protect endangered and threatened species could prohibit drilling in certain areas, impact suppliers of critical materials or services, or require the implementation of expensive mitigation measures. Additionally, federal statutes, including the CWA, the OPA and CERCLA, as well as comparable state laws, prohibit certain actions that adversely affect critical habitat, wetlands and natural resources. If harm to species or damages to wetlands, habitat or natural resources occur or may occur, government entities or, at times, private parties may act to prevent oil and gas exploration or development activities or seek damages for harm to species, habitat or natural resources resulting from drilling, construction or releases of petroleum hydrocarbons, wastes, hazardous substances or other regulated materials, and, in some cases, may seek criminal penalties.
Moreover, as a result of one or more settlements entered into by the FWS, the agency is required to make determinations on the potential listing of these individualsnumerous species as endangered or threatened under the ESA. The designation of previously unprotected species as threatened or endangered in areas where the Company conducts operations could cause the Company to incur increased costs arising from species protection measures or could result in delays, restrictions or prohibitions on its development and production activities that could have a detrimentalmaterial adverse effect on us. In addition, our drilling success and the success of other activities integral to our operations will depend, in part, on ourCompany’s ability to attractdevelop and retain experienced geologists, engineers and other professionals. Competition for experienced geologists, engineers and some other professionals is intense. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be harmed.produce reserves.
We are subject to complex laws and regulations, including environmental regulations, which can adversely affect the cost, manner or feasibility of doing business.
Our operations are subject to extensive federal, state and local laws and regulations, including tax laws and regulations and those relating to the generation, storage, handling, emission, transportation and discharge of materials into the environment. These laws and regulations can adversely affect the cost, manner or feasibility of doing business. Many laws and regulations require permits for the operation of various facilities, and these permits are subject to revocation, modification and renewal. Governmental authorities have the power to enforce compliance with their regulations, and violations could subject us to fines, injunctions or both. These laws and regulations have increased the costs of planning, designing, drilling, installing and operating natural gas and oil facilities. In addition, we may be liable for environmental damages caused by previous owners of property we purchase or lease. Risks of substantial costs and liabilities related to environmental compliance issues are inherent in natural gas and oil operations.
It is possible that other developments, such as stricter environmental laws and regulations, and claims for damages to property or persons resulting from natural gas and oil production, would result in substantial costs and liabilities.
Increasing scrutiny and changing expectations from investors, lenders and other market participants with respect to our Environmental, Social and Governance (“ESG”) policies may impose additional costs on us or expose us to additional risks.
Companies across all industries are facing increasing scrutiny relating to their ESG policies. Investor advocacy groups, certain institutional investors, investment funds, lenders and other market participants are increasingly focused on ESG practices and in recent years have placed increasing importance on the implications and social cost of their investments. The Company’sincreased focus and activism related to ESG and similar matters may hinder access to capital, as investors and lenders may decide to reallocate capital or not to commit capital as a result of their assessment of a company’s ESG practices. Companies that do not adapt to or comply with investor, lender or other industry shareholder expectations and standards, which are evolving, or which are perceived to have not responded appropriately to the growing concern for ESG issues, regardless of whether there is a legal requirement to do so, may suffer from reputational damage and the business, financial condition or stock price of such a company could be negatively affected by security threats, including cybersecurity threats,materially and adversely affected.
We may face increasing pressures from investors, lenders and other disruptions.market participants, who are increasingly focused on climate change, to prioritize sustainable energy practices, reduce our carbon footprint and promote sustainability. As a result, we may be required to implement more stringent ESG procedures or standards so that our existing and future investors and lenders remain invested in us and make further investments in us. If we do not meet these standards, our business or our ability to access capital could be harmed.
As an oil
Additionally, certain investors and gas producer,lenders have and may continue to exclude companies engaged in exploration and production activity, such as us, from their investing portfolios altogether due to ESG factors. These limitations in both the Company faces various security threats,debt and equity capital markets may affect our ability to grow as our plans for growth may include accessing those markets. If those markets are unavailable, or if we are unable to access alternative means of financing on acceptable terms, or at all, we may be unable to implement our business strategy, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness. At the same time, some stakeholders and regulators have increasingly expressed or pursued opposing views, legislation, and investment expectations with respect to ESG, including cybersecurity threatsthe enactment or proposal of “anti-ESG” legislation or policies.
Further, it is likely that we will incur additional costs and require additional resources to gain unauthorizedmonitor, report and comply with wide ranging ESG requirements, including the SEC climate change disclosure rules. Similarly, these policies may negatively impact the ability of our customers to access to sensitive information or to render data or systems unusable; threats to the securitydebt and capital markets. The occurrence of any of the Company’s facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. The potential for such security threats has subjected the Company’s operations to increased risks thatforegoing could have a material adverse effect on the Company’s business. In particular, the Company’s implementation of various proceduresour business and controls to monitor and mitigate security threats and to increase security for the Company’s information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essentialfinancial condition.
Changes to the Company’s operations andU.S. federal tax laws could have a material adverse effect on the Company’s reputation,adversely affect our financial position, results of operations and cash flow.
Our future effective tax rates could be adversely affected by changes in tax laws, both domestically and internationally, or cash flows. Cybersecurity attacksthe interpretation or application thereof. From time to time, U.S. and foreign tax authorities, including state and local governments consider legislation that could increase our effective tax rate.
The IRA includes a 1% tax on publicly traded corporations on the fair market value of stock repurchased during any taxable year. Such tax applies to the extent such buybacks exceed $1 million during such year, which buyback value may be offset by other stock issuances.
Further, the U.S. Congress has advanced a variety of tax legislation proposals, and while the final form of any legislation is uncertain, the current proposals, if enacted, could have a material effect on our effective tax rate. Additionally, in particular are becoming more sophisticatedrecent years, lawmakers and the U.S. Department of the Treasury have proposed certain significant changes to U.S. tax laws applicable to oil and gas companies. These changes include, but are not limited to; (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, and (iii) an extension of the amortization period for certain geological and geophysical expenditures. No accurate prediction can be made as to malicious software, attemptswhether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. This legislation or any future similar changes in U.S. federal income tax laws, as well as any similar changes in state law, could eliminate or postpone certain tax deductions that currently are available with respect to gain unauthorized access to datanatural gas and systems,oil exploration and other electronic security breaches thatproduction, which could lead to disruptions in critical systems, unauthorized releasenegatively affect our results of confidential or otherwise protected information,operations and corruption of data. These events could damage the Company’s reputation and lead to financial losses from remedial actions, loss of business or potential liability.condition.
Item 1B. | UNRESOLVED STAFF COMMENTS. |
We are a smaller reporting company and therefore no response is required pursuant to this Item.
Item | CYBERSECURITY |
As an oil and gas producer, the Company is dependent on digital technology in many areas of its business and operations. Additionally, the Company gathers and safeguards sensitive information as a part of its regular business activities. The Company continually evaluates and integrates new processes, systems and resources to enhance its defenses against cybersecurity threats.
Governance
The Board is responsible for overseeing the Company’s enterprise risk management processes and has delegated oversight of cybersecurity and other information technology risks to the Executive Committee, a standing committee of the Board. The Executive Committee oversees management’s implementation and execution of the Company’s Cybersecurity Program and IRP. The Executive Committee receives in-depth annual reports from the Director of Information Technology (DIT) or Assistant Director of Information Technology (ADIT)detailing relevant cybersecurity risks to the Company and, as necessary, timely periodic updates based on circumstances, regarding any significant cybersecurity incidents or developments. The Executive Committee reports to the Board regarding its activities, including those related to cybersecurity.
At the management level, the Company's cybersecurity governance includes a Cybersecurity Steering Committee which is comprised of a subset of the Company's Executive Committee and other key officers, leaders, and subject matter experts from various disciplines across the Company. The Cybersecurity Steering Committee meets quarterly to receive updates from the DIT and/or ADIT on Company-related cyber risks, monitor compliance with the Company's Cyber Security Program, and to review cybersecurity policies.
The Company’s cybersecurity risk management and strategy processes are managed by the DIT and the ADIT who have 40 and 20 years of work experience, respectively, in various roles involving systems security, operations and compliance. These individuals are informed about and monitor the prevention, detection, mitigation and remediation of cybersecurity incidents through their management of internal information technology personnel and retained third-party personnel involved in the cybersecurity risk management and strategy processes described above, including the operation of the IRP.
Cybersecurity Program Management
The Company has developed and implemented an information security program (the Cybersecurity Program), which includes various processes and controls intended to protect the confidentiality, integrity and availability of the Company's systems and information. We have also implemented an incident response plan (the IRP) that applies in the event of a cybersecurity threat or incident to provide a standardized framework for responding to security incidents. The IRP sets out a coordinated approach to investigating, containing, documenting and mitigating incidents, including reporting findings and keeping senior management and other key stakeholders informed and involved as appropriate.
The Company’s Cybersecurity Program and incident response processes were primarily designed and assessed to align with the cybersecurity framework published by the National Institute of Standards and Technology. In addition to our internal cybersecurity capabilities, the Company retains or engages various third-parties in connection with design, implementation and monitoring of certain cybersecurity-related processes and controls.
Key aspects of the Company’s Cybersecurity Program include:
■ | Risk assessments designed to help identify material cybersecurity risks to critical systems and the company-wide information technology environment; | |
■ | Continuous monitoring of Company systems and conducting periodic penetration tests; | |
■ | An IRP that includes procedures for responding to cybersecurity incidents; | |
■ | Required cybersecurity trainings for employees, incident response personnel, and management related to physical security of assets, data privacy and other information security policies and procedures; and | |
■ | A third-party risk management process for its service providers, suppliers, vendors and other business associates. |
The Cybersecurity Program is integrated into the Company’s overall enterprise risk management process and shares common methodologies, reporting channels, and governance processes that apply across the enterprise risk management process to other legal, compliance, strategic, operational, and financial risk areas. Cyber risks identified in the overall enterprise risk management process are reviewed annually by the Executive Committee.
Risks from Cybersecurity Threat
As of the date of this Annual Report on Form 10-K, the Company has not identified any cybersecurity incidents, including any prior cybersecurity incidents, that have materially affected the Company's operations, business strategy, results of operations and cash flows. The Company faces various ongoing risks from cybersecurity threats that, if realized, are reasonably likely to lead to losses of sensitive information, critical infrastructure or capabilities essential to the Company's operations and could have a material adverse effect on the Company's reputation, financial position, results of operations and cash flows. See "Item 1A. Risk Factors - The Company's business could be materially and adversely affected by security threats, including cybersecurity threats, and other disruptions" for additional information.
Item 2. | PROPERTIES. |
Our executive offices, as well as offices of Prime Operating Company, Eastern Oil Well Service Company and EOWS Midland Company and Prime Offshore L.L.C., are located in leased premises in Houston, Texas, and the offices of Southwest Oilfield Construction Company are in Oklahoma City, Oklahoma. We also maintain leased office space at One Landmark Square, Stamford, Connecticut for the administration, accounting and tax preparation for the Partnerships and Trusts.Texas.
We maintain district offices in Houston and Midland, Texas and Oklahoma City, Oklahoma and Charleston, West Virginia, and have field offices in Carrizo Springs and Midland, Texas, as well as, Elmore City, Oklahoma and Orma, West Virginia.
Substantially all of our oil and gas properties are subject to a mortgage given to collateralize indebtedness or are subject to being mortgaged upon request by our lenders for additional collateral.
The information set forth below concerning our properties, activities, and oil and gas reserves includeincludes our interests in affiliated entities.
The following table sets forth the exploratory and development drilling experience with respect to wells in which we participated during the three years ended December 31, 2015.2023.
| 2015 | 2014 | 2013 | 2023 | 2022 | 2021 | |||||||||||||||||||||||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||||||||||||||||
Exploratory: | ||||||||||||||||||||||||||||||||||||||||||||||||
Oil | — | — | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||
Gas | — | — | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||
Dry | — | — | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||
Development: | ||||||||||||||||||||||||||||||||||||||||||||||||
Oil | 8 | 3.6 | 25 | 11.79 | 23 | 13.60 | 35 | 8.37 | 8 | 0.76 | 13 | 4.73 | ||||||||||||||||||||||||||||||||||||
Gas | — | — | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||
Dry | — | — | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||
Total: | ||||||||||||||||||||||||||||||||||||||||||||||||
Oil | 8 | 3.6 | 25 | 11.79 | 23 | 13.60 | 35 | 8.37 | 8 | 0.76 | 13 | 4.73 | ||||||||||||||||||||||||||||||||||||
Gas | — | — | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||
Dry | — | — | — | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||
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| 8 | 3.6 | 25 | 11.79 | 23 | 13.60 | 35 | 8.37 | 8 | 0.76 | 13 | 4.73 | |||||||||||||||||||||||||||||||||||||
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Oil and Gas Production
As of December 31, 2015,2023, we had ownership interestsinterest in the following numbersnumber of gross and net producing oil and gas wells(1).
| Gross | Net | |||||||
Producing wells(1): | ||||||||
Oil Wells | 901 | 429 | ||||||
Gas Wells | 945 | 478 | ||||||
Gross | Net | |||||||
Producing Oil Wells(1) | 898 | 400 | ||||||
Producing Gas Wells(1) | 220 | 33 | ||||||
(1) | A gross well is a well in which a working interest is owned. A net well is the sum of the fractional |
The following table shows our net production of oil, NGL and natural gas for each of the three years ended December 31, 2015.2023. “Net” production is net after royalty interests of others are deducted and is determined by multiplying the gross production volume of properties in which we have an interest by the percentage of the leasehold, mineral or royalty interest owned by us.
| 2015 | 2014 | 2013 | 2023 | 2022 | 2021 | |||||||||||||||||||
Oil (barrels) | 720,000 | 759,000 | 730,000 | 1,144,000 | 939,000 | 738,000 | ||||||||||||||||||
NGL (barrels) | 606,000 | 417,000 | 416,000 | |||||||||||||||||||||
Gas (Mcf) | 4,696,000 | 4,741,000 | 4,897,000 | 4,127,000 | 3,325,000 | 3,236,000 | ||||||||||||||||||
The following table sets forth our average sales price per barrel of oil and average sales prices per one thousand cubic feet (“Mcf”) of gas, together with our average production costs per unit of production for the three years ended December 31, 2014.2023.
| 2015 | 2014 | 2013 | ||||||||||
Average sales price per barrel | $ | 70.93 | $ | 86.68 | $ | 90.85 | ||||||
Average sales price per Mcf | 3.35 | 5.15 | 5.13 | |||||||||
Average production costs per net equivalent barrel(1) | 21.24 | 25.51 | 25.21 | |||||||||
2023 | 2022 | 2021 | ||||||||||
Average sales price per barrel of oil | $ | 76.84 | $ | 96.70 | $ | 68.39 | ||||||
Average sales price per barrel of NGL | $ | 19.64 | $ | 35.70 | $ | 26.97 | ||||||
Average sales price per Mcf of natural gas | $ | 1.93 | $ | 5.54 | $ | 3.53 | ||||||
Average production costs per net equivalent barrel of oil(1) | $ | 12.98 | $ | 16.07 | $ | 13.76 | ||||||
(1) | Net equivalent barrels are computed at a rate of 6 Mcf per barrel and costs exclude production taxes. |
Average oil, NGL and gas prices received excludingincluding the impact of derivatives were:
| 2015 | 2014 | 2013 | ||||||||||
Oil Price per barrel | $ | 45.74 | $ | 86.73 | $ | 93.75 | ||||||
Gas Price per Mcf | 2.71 | 5.32 | 4.97 | |||||||||
2023 | 2022 | 2021 | ||||||||||
Average sales price per barrel of oil | $ | 76.33 | $ | 87.77 | $ | 64.04 | ||||||
Average sales price per barrel of NGL | $ | 19.64 | $ | 35.70 | $ | 26.97 | ||||||
Average sales price per Mcf of natural gas | $ | 1.93 | $ | 4.44 | $ | 2.97 | ||||||
Acreage
The following table sets forth the approximate gross and net undeveloped acreage in which we have leasehold and mineral interests as of December 31, 2015.2023. “Undeveloped acreage” is that acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether or not such acreage contains proved reserves.
| Developed | Undeveloped | Total | Developed | Undeveloped | Total | |||||||||||||||||||||||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||||||||||||||||
Leasehold acreage | 199,684 | 95,550 | 349 | 336 | 200,033 | 95,886 | 84,668 | 24,725 | — | — | 84,668 | 24,725 | ||||||||||||||||||||||||||||||||||||
Mineral fee acreage | 1,640 | 117 | 19,257 | 417 | 20,897 | 534 | 1,640 | 117 | 19,257 | 417 | 20,897 | 534 | ||||||||||||||||||||||||||||||||||||
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Total | 201,324 | 95,667 | 19,606 | 753 | 220,930 | 96,420 | 86,308 | 24,842 | 19,257 | 417 | 105,565 | 25,259 | ||||||||||||||||||||||||||||||||||||
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Total Net Undeveloped Acreage Expiration
In the event that production is not established, or we take no action to extend or renew the terms of our leases, our net undeveloped acreage that will expire over the next three years, as of December 31, 20152023, is 22zero acres for the year ending December 31, 2017,2024, zero in 2025, and nonezero acres in 2016 and 2018.2026.
Reserves
Our
All of our interests including the interests held by the Partnerships, in proved developed and undeveloped oil and gas properties have been evaluated by Ryder Scott Company, L.P. for each of the three years ended December 31, 2015.2023. The professional qualifications of the technical persons primarily responsible for overseeing the preparation of the reservesreserve estimates can be found in Exhibit 99.1, the Ryder Scott Company, L.P. Report on Registrant’s Reserves Estimates. In matters related to the preparation of our reserve estimates, our district managers report to the Houston CentralEngineering Data manager, who maintains oversight and compliance responsibility for the internal reserve estimate process and provides oversight for the annual preparation of reserve estimates of 100% of our year-end reserves by our independent third partythird-party engineers, Ryder Scott Company, L.P. The members of our district and central groupsdistricts consist of degreed engineers and geologists and geophysicists and technicians with between approximately ten and thirty-fiveover twenty-five years of industry experience and between threeten and twentytwenty-five years of experience managing our reserves. Our Houston CentralEngineering Data manager, the technical person primarily responsible for overseeing the preparation of reserves estimates, has over twenty-fivethirty years of experience, holds a Bachelor of Science degree in Natural Gas EngineeringGeology and an MBA in finance and is a member of the Society of Petroleum Engineers and American Association of Petroleum Geologists.Geologist. See Part II, Item 8.,8 “Financial Statements and Supplementary Data”, for additional discussions regarding proved reserves and their related cash flows.
All of our reserves are located within the continental United States. The following table summarizes our oil and gas reserves at each of the respective dates:
| Reserve Category | ||||||||||||||||||||||||||||||||||||||||||||||||
| Proved Developed | Proved Undeveloped | Total | ||||||||||||||||||||||||||||||||||||||||||||||
As of December 31, | Oil (MBbls) | NGLs (MBbls) | Gas (MMcf) | Total (MBoe) | Oil (MBbls) | NGLs (MBbls) | Gas (MMcf) | Total (MBoe) | Oil (MBbls) | NGLs (MBbls) | Gas (MMcf) | Total (MBoe) | ||||||||||||||||||||||||||||||||||||
| (a) | (a) | (a) | ||||||||||||||||||||||||||||||||||||||||||||||
2013 | 6,687 | 2,223 | 31,628 | 14,182 | 9,066 | 3,707 | 19,772 | 16,068 | 15,753 | 5,930 | 51,400 | 30,250 | ||||||||||||||||||||||||||||||||||||
2014 | 6,239 | 2,160 | 32,267 | 13,777 | 14,709 | 4,322 | 26,331 | 23,420 | 20,948 | 6,482 | 58,958 | 37,197 | ||||||||||||||||||||||||||||||||||||
2015 | 4,579 | 1,673 | 23,275 | 10,131 | 52 | 12 | 55 | 73 | 4,631 | 1,685 | 23,330 | 10,204 | ||||||||||||||||||||||||||||||||||||
Reserve Category Proved Developed Proved Undeveloped Total As of December 31, Oil NGLs Gas Total Oil NGLs Gas Total Oil NGLs Gas Total 2021 2022 2023
(MBbls)
(MBbls)
(MMcf)
(MBoe)
(MBbls)
(MBbls)
(MMcf)
(MBoe)
(MBbls)
(MBbls)
(MMcf)
(MBoe) 5,386 2,882 23,902 12,252 — — — — 5,386 2,882 23,902 12,252 4,143 2,497 22,277 10,353 3,028 1,833 9,030 6,366 7,171 4,330 31,307 16,719 5,757 3,676 24,749 13,558 6,254 5,156 24,470 15,488 12,011 8,832 49,219 29,046
(a) | In computing total reserves on a barrels of oil equivalent (Boe) |
Proved undeveloped
During 2021, in West Texas, we participated with Apache in the drilling of three additional horizontals on the Kashmir Tract in Upton County, Texas and completed these three wells in September of 2021 along with six other wells drilled in 2020 on the same lease that were drilled but uncompleted at year-end. The Company has an average of 47.8% interest in these nine wells and invested approximately $30 million in these horizontal wells. Also in 2021, the Company participated with Ovintiv Mid-Continent for 11.25% interest in four two-mile horizontal wells in Canadian County, Oklahoma. Twelve of these thirteen horizontal wells were successfully completed and placed into production in the fourth quarter of 2021. One of the Ovintiv wells had a casing leak issue and has been temporarily abandoned. The Company invested approximately $32 million in these thirteen wells. In addition, in 2021, the Company added minor reserves of 16,068 MBoe as ofthrough over-riding royalty interest in two wells drilling and completed in Grady County, Oklahoma.
At December 31, 2013 included 148 drilling locations2021, the Company had 159 Mboe of proved developed shut-in reserves attributable to three horizontals drilled and completed in our West Texas drilling program, 10 drilling locations in our Mid-Continent region and 4 drilling locations in our Gulf Coast region. During 2014 weCanadian County, Oklahoma, but not yet online at year-end. These reserves were converted 623 MBoe to proved developed producing reserves at a cost of $11.8 million. Following our strategic plan to reduce vertical drilling and increase horizontal drilling we removed 49 vertical drilling locations and added 34 horizontal drilling locations to our West Texas drilling plan. Proved undeveloped reserves of 23.4 MBoe as of December 31, 2014 included 126 drilling locations in our West Texas drilling program, 10 drilling locations in our Mid-Continent region and 3 drilling locations in our Gulf Coast region.
During 2015 we converted 997 MBoe to proved developed producing reserves at a cost of $7.9 million. Future development plans are reflective of the significant decrease in commodity prices and have been established based on an expectation of available cash flows from operations and availability under our revolving credit facility. As of December 31, 2015, we removed all but one PUD location from our year end reserve report due to the uncertainty of available capital for drilling expenditure. The PUD location included in the report was drilled in the first quarter of 2016.2022. At year-end 2021, we did not include proved undeveloped reserves in our reserve report because we had not yet received definitive drilling proposals from third-party operators for the more than fifteen horizontal wells that we planned to participate in located primarily in West Texas.
We employ technologies
In 2022, the Company participated in eight horizontal wells that were drilled and completed; four located in Irion County, West Texas, operated by SEM Operating Company, in which we have 10.13% interest, and four located in Canadian County, Oklahoma, operated by Ovintiv Mid-Continent, Inc., in which we have an average 9% interest. Our investment in these eight wells was approximately $4 million and all were brought on production in August of 2022. In addition, the Company added reserves through 15 wells in which we have various minor over-riding royalty interest. Eight of these wells are located in West Texas and seven are located in Oklahoma.
In the fourth quarter of 2022, we began participation in the drilling of 20 horizontal wells located in West Texas operated by three different operators. In Martin County, we participated with ConocoPhillips in five 2.5-mile-long horizontal wells in which the Company has 20.83% interest and had capital investment of $12.1 million. In Reagan County, we participated with Hibernia Energy III (now Civitas Resources) in 10 two-mile horizontals with 25% interest and an investment of approximately $25.6 million. Also in Reagan County, we participated with Double Eagle (DE IV) in five two-mile-long horizontals with nearly 50% interest, carrying a net capital outlay of $23.4 million. All twenty of these West Texas wells were completed and online in the second quarter of 2023.
At year-end 2022, the Company had 6,366 Mboe of proved undeveloped reserves attributable to establishthe 25 horizontal wells described above.
In 2023, the Company participated with five operators in the drilling and completion of 35 horizontal wells: 32 of these are located in West Texas and three are located in Oklahoma. In total, including the cost of facilities, the Company invested approximately $91 million, 99% of which is attributable to the wells in West Texas where we have been drilling horizontal wells targeting various proven pay intervals in the Wolfcamp and Spraberry formations. At December 31, 2023, we had 12 wells completed but not producing that were all brought into production in January of 2024. These 12 wells account for 1,278 MBOE of proved developed reserves at year-end. In addition, as of December 31, 2023, the Company was in the process of drilling and completing 34 wells in West Texas, 28 of which are considered proved undeveloped, and six of which are considered probable undeveloped. The year-end reserve report includes only proved reserves, that have been demonstrated to provide consistent results capable of repetition. The technologies and economic data being usedtherefore expected reserves from the six probable undeveloped wells are not included in the estimationreserve report.
At year-end 2023, the Company had 15,489 MBOE of our proved undeveloped reserves include, butthat are not limitedattributable to electrical logs, radioactivity logs, geologic maps, production data and well test data. The estimated reserves52 undeveloped wells, 28 of wells with sufficient production history are estimated using appropriate decline curves. Estimated reserves of producing wells with limited production history and for undeveloped locations are estimated using performance data from analogous wellswhich were in the area. These wells are considered analogous based on production performance from the same formation and with similar completion techniques.process of being drilled or completed at year-end.
The estimated future net revenue (using current prices and costs as of those dates) and the present value of future net revenue (at a 10% discount for estimated timing of cash flow) for our proved developed and proved undeveloped oil and gas reserves at the end of each of the three years ended December 31, 2015,2023, are summarized as follows (in thousands of dollars):
| Proved Developed | Proved Undeveloped | Total | ||||||||||||||||||||||||||||||
As of December 31, | Future Net Revenue | Present Value 10 Of Future Net Revenue | Future Net Revenue | Present Value 10 Of Future Net Revenue | Future Net Revenue | Present Value 10 Of Future Net Revenue | Present Value 10 Of Future Income Taxes | Standardized Measure of Discounted Cash flow | ||||||||||||||||||||||||
2013 | $ | 341,841 | $ | 204,326 | $ | 455,622 | $ | 131,510 | $ | 797,463 | $ | 335,836 | $ | 97,608 | $ | 238,228 | ||||||||||||||||
2014 | $ | 295,554 | $ | 185,566 | $ | 864,024 | $ | 312,073 | $ | 1,159,578 | $ | 497,639 | $ | 154,351 | $ | 343,288 | ||||||||||||||||
2015 | $ | 70,834 | $ | 60,962 | $ | 1,098 | $ | 233 | $ | 71,932 | $ | 61,195 | $ | 2,393 | $ | 58,802 | ||||||||||||||||
Proved Developed | Proved Undeveloped | Total | ||||||||||||||||||||||||||||||
As of December 31, | Future Net | Present | Future Net | Present | Future Net | Present | Present | Standardized | ||||||||||||||||||||||||
2021 | $ | 275,227 | $ | 171,906 | $ | — | $ | — | $ | 275,227 | $ | 171,906 | $ | 36,100 | $ | 135,806 | ||||||||||||||||
2022 | $ | 320,146 | $ | 192,688 | $ | 200,790 | $ | 118,081 | $ | 520,936 | $ | 310,769 | $ | 66,233 | $ | 244,536 | ||||||||||||||||
2023 | $ | 314,415 | $ | 213,281 | $ | 253,959 | $ | 138,679 | $ | 568,374 | $ | 351,960 | $ | 73,912 | $ | 278,048 | ||||||||||||||||
The PV 10PV10 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 PV 10PV10 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 PV 10PV10 of future income taxes represents the sole reconciling item between this non-GAAP PV 10PV10 Value versus the GAAP measure presented in the standardized measure of discounted cash flow. A reconciliation of these values is presented in the last three columns of the table above. The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to proved oil and natural gas reserves after income tax, discounted at 10%.
“Proved developed” oil and gas reserves are reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. “Proved undeveloped” oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Our reserves include amounts attributable to non-controlling interests in the Partnerships. These interests represent less than 10% of our reserves.
In accordance with U.S. generally accepted accounting principles, product prices are determined using the twelve-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first day of the month price for each month, adjusted for oilfield or gas gathering hub and wellhead price differentials (e.g. grade, transportation, gravity, sulfur, and basic sediment and water) as appropriate. Also, in accordance with SEC specifications and U.S. generally accepted accounting principles, changes in market prices subsequent to December 31 are not considered.
While it may be reasonably be anticipated that the prices received for the sale of our production may be higher or lower than the prices used in this evaluation, as described above, and the operating costs relating to such production may also increase or decrease from existing levels, such possible changes in prices and costs were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation for the SEC case. Actual volumes produced, prices received and costs incurred may vary significantly from the SEC case.
Natural gas prices, based on the twelve-month average of the first of the month Henry Hub index price, were $2.59$2.64 per MmbtuMMBtu in 20152023 as compared to $4.35$6.36 per MmbtuMMBtu in 2014,2022 and have continued to decline to $2.19$3.60 per MmbtuMMBtu in February 2016.2021. Oil prices, based on the NYMEX monthlyWest Texas Intermediate (WTI) Light Sweet Crude first of the month average spot price, were $50.28$78.22 per barrel in 20152023 as compared to $94.99$93.67 per barrel in 2014,2022, and have continued to decline to $31.78$66.56 per barrel in January 2016.
2021. Since January 1, 2016,2023, we have not filed any estimates of our oil and gas reserves with, nor were any such estimates included in any reports to, any federal authority or agency, other than the Securities and Exchange Commission.
District Information
The following table presentsrepresents certain reserve, productionreserves and well information as of December 31, 2015.2023.
| Appalachian | Gulf Coast | Mid- Continent | West Texas | Other | Total | |||||||||||||||||||
Proved Reserves at Year End (MBoe) | ||||||||||||||||||||||||
Developed | 646 | 1,060 | 2,263 | 6,078 | 82 | 10,129 | ||||||||||||||||||
Undeveloped | — | — | — | 73 | — | 73 | ||||||||||||||||||
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Total | 646 | 1,060 | 2,263 | 6,151 | 82 | 10,202 | ||||||||||||||||||
Average Daily Production (Boe per day) | 344 | 428 | 1,356 | 1,930 | 63 | 4,121 | ||||||||||||||||||
Gross Wells | 627 | 291 | 558 | 453 | 84 | 2,013 | ||||||||||||||||||
Net Wells | 325 | 166 | 269 | 204 | 20 | 984 | ||||||||||||||||||
Gross Operated Wells | 469 | 257 | 248 | 356 | 57 | 1,387 | ||||||||||||||||||
Gulf | Mid- | West | Other | Total | ||||||||||||||||
Proved Reserves as of December 31, 2023 (MBoe) | ||||||||||||||||||||
Developed | 563 | 2,210 | 10,778 | 7 | 13,558 | |||||||||||||||
Undeveloped | — | — | 15,488 | — | 15,488 | |||||||||||||||
Total | 563 | 2,210 | 26,266 | 7 | 29,046 | |||||||||||||||
Average Net Daily Production (Boe per day) | 173 | 831 | 6,172 | 4 | 7,181 | |||||||||||||||
Gross Productive Wells (Working Interest and ORRI Wells) | 114 | 511 | 647 | 222 | 1,494 | |||||||||||||||
Gross Productive Wells (Working Interest Only) | 72 | 361 | 541 | 144 | 1,118 | |||||||||||||||
Net Productive Wells (Working Interest Only) | 21 | 132 | 275 | 5 | 433 | |||||||||||||||
Gross Operated Productive Wells | 28 | 128 | 334 | — | 490 | |||||||||||||||
Gross Operated Water Disposal, Injection and Supply wells | 5 | 39 | 8 | — | 52 | |||||||||||||||
In several of our producing regions we operatehave field service groups to service our operated wells and locations as well as third partythird-party operators in the area. These services consist of well service support, site preparation and construction services for drilling and workover operations. Our operations are performed utilizing workover or swab rigs, water transport trucks, saltwater disposal facilities, various land excavating equipment and trucks we own and that are operated by our field employees.
Appalachian Region
Our Appalachian activities are concentrated primarily in West Virginia. This region is managed from our office in Charleston, West Virginia. Our assets in this region include a large acreage position and a high concentration of wells. At December 31, 2015, we had 627 wells (325 net), of which 469 wells are operated by us. There are multiple producing intervals that include the Big Lime, Injun, Blue Monday, Weir, Berea, Gordon and Devonian Shale formations at depths primarily ranging from 1,600 to 5,600 feet. Average net daily production in 2015 was 344 Boe. While natural gas production volumes from Appalachian reservoirs are relatively low on a per-well basis compared to other areas of the United States, the productive life of Appalachian reserves is relatively long. At December 31, 2015, we had 646 MBoe of proved reserves (substantially all natural gas) in the Appalachian region, constituting 6% of our total proved reserves. We maintain an acreage position of over 40,200 gross (33,400 net) acres in this region, primarily in Calhoun, Clay and Roane counties. We operate a small field service group in this region utilizing one swab rig, one paraffin truck, one saltwater hauling truck and limited excavating equipment to primarily service our own operated wells and locations. As of March 30, 2016 the Appalachian region has no wells in the process of being drilled, no waterfloods in the process of being installed and no other related activities of material importance.
Gulf Coast Region
Our development, exploitation, exploration and production activities in the Gulf Coast region are primarily concentrated in Louisiana, southeast Texas and south Texas. This region is managed from our office in Houston, Texas. Principal producing intervals are in the Marg Tex, Wilcox, Pettit, Glenrose, Woodbine, San Miguel, Olmos, and Yegua formations at depths ranging from 3,000 to
12,500 feet. We had 291114 producing wells (166(21 net) in the Gulf Coast region as of December 31, 2015,2023, of which 25728 wells are operated by us. Average net daily production in 2015our Gulf Coast Region at year-end 2023 was 428173 Boe. At December 31, 2015,2023, we had 428563 MBoe of proved reserves in the Gulf Coast region, which represented 10%2% of our total proved reserves. We maintain an acreage position of over 20,0007,468 gross (9,500(4,699 net) acres in this region, primarily in Dimmit, DuvalColorado, Newton, and Polk counties. We operate a field service group in this region from a field office in Carrizo Springs, Texas utilizing 3two workover rigs, 18twenty water transport trucks, onetwo hot-oil trucks, a cement truck, and two saltwater disposal well and several trucks and excavating equipment. Services including well service support, site preparation and constructionwells to provide oil field services for drilling and workover operations are provided to third partythird-party operators as well as utilized in our own operated wells and locations.South Texas. As of March 30, 201631, 2024, the Gulf Coast region has no operated wells in the process of being drilled, no waterfloods in the process of being installed and no other related activities of material importance.
Mid-Continent Region
Our Mid-Continent activities are concentrated in central Oklahoma. This region is managed from our office in Oklahoma City, Oklahoma. As of December 31, 2015,2023, we had 558511 producing wells (269(132 net) in the Mid-Continent area, of which 248128 wells are operated by us. Principal producing intervals are in the Roberson,Robberson, 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 2015our Mid-Continent Region in 2023 was 1,356831 Boe. At December 31, 2015,2023, we had 2,2632,210 MBoe of proved reserves in the Mid-Continent area, or 22%representing 8% of our total proved reserves. We maintain an acreage position of over 86,000approximately 46,960 gross (29,000(10,137 net) acres in this region, primarily in Canadian, Kingfisher, Grant, Major, and KingfisherGarvin counties. We operate a field service group in this region from a field office in Elmore City, utilizing one workover rig and 1 saltwater hauling truck. As of March 30, 2016 theOur Mid-Continent region has no wellsis actively participating with third-party operators in the processhorizontal development of being drilled, no waterfloodslands that include Company owned interest in several counties in the processStack and Scoop plays of being installedOklahoma where drilling is primarily targeting reservoirs of the Mississippian, and no other related activities of material importance.Woodford formations.
West Texas Region
Our West Texas activities are concentrated in the Permian Basin in Texas and New Mexico. The Spraberry field was discovered in 1949, encompasses eight counties in West Texas and the Company believes it is the largest oil field in the United States. The field is approximately 150 miles long and 75 miles wide at its widest point. The oil produced is West Texas Intermediate Sweet, and the gas produced is casinghead gas with an average energy content of 1,400 Btu. The oil and gas in this basin are produced primarily from six formations,five intervals; the upperUpper and lowerLower Spraberry, the Dean, the Wolfcamp, the Strawn, and the Atoka, at depths ranging from 6,700 feet to 11,300 feet. This region is managed from our office in Midland, Texas. As of December 31, 2015,2023, we had 453647 wells (204(275 net) in the West Texas area, of which 356334 wells are operated by us. Principal producing intervals are in the Spraberry, Wolfcamp, and San Andres formations at depths ranging from 5,5004,200 to 12,500 feet. Average net daily production in 2015Our West Texas Region at year-end 2023 was 1,9306,172 Boe. At December 31, 2015,2023, we had 6,15126,267 MBoe of proved reserves in the West Texas area, or 60%90% of our total proved reserves. We maintain an acreage position of over 26,000approximately 16,407 gross (16,500(9,341 net) acres in the Permian Basin in West Texas, primarily in Reagan, Upton, Martin and Midland counties. We have currently identified one proved undeveloped drilling location therecounties and believe this acreage has significant resource potential for horizontal drilling in the Spraberry, Jo Mill, and Wolfcamp intervals for additional drilling locations opportunities.intervals. We operate a field service group in this region utilizing 8nine workover rigs, 4three hot oiler trucks, and 1one kill truck. Services including well serviceOil field support site preparation and construction servicesis provided for drilling and workover operations are providedboth to third partythird-party operators as well as utilized infor our own operated wells and locations.
As of March 30, 201631, 2024, the Company was participating in the drilling or completion of 34 horizontal wells in Reagan County, Texas with an average of 39% interest in 14 wells, 8.3% in 12 wells, 50% in six wells and less than 1% in two wells. Combined, we expect to spend approximately $80 million in these horizontals and their associated facilities. Twenty-eight of these 34 wells and their forecast reserves are included in the 2023 year-end reserve report as proved undeveloped, whereas the reserves of six wells are considered probable undeveloped and not included in the reserve report. Additionally, we have 12 horizontals slated to begin drilling in the second quarter of 2024 and be on production in the third quarter.
In 2024, we expect to complete 54 new horizontal wells, investing approximately $140 million. We are also preparing to invest approximately $95 million in another 23 horizontal wells to be drilled and completed in 2025. In addition, we have identified 28 horizontal locations for future development in West Texas region has no wellsthat we anticipate to be drilled in the process2026-2027 timeframe and would require a net investment of being drilled, no waterfloods in the process of being installed and no other related activities of material importance.approximately $67 million.
Item 3. | LEGAL PROCEEDINGS. |
None.
In the ordinary course of conducting our business, we become involved in litigation and other claims from private party actions, as well as judicial and administrative proceedings involving governmental authorities at the federal, state, and local levels. While the outcome of litigation or other proceedings against us cannot be predicted with certainty, management does not expect that any loss resulting from such litigation or other proceedings, in excess of any amounts accrued or covered by insurance, will have a material adverse impact on our consolidated financial statements.
Item 4. | MINE SAFETY DISCLOSURES. |
Not applicable.
PART II—OTHER INFORMATION
Item 5. | MARKET FOR |
Our common stock is listed and principally traded on the NASDAQNasdaq Stock Market under the ticker symbol “PNRG”. The following table presents the high and low prices per share of our common stock during certain periods, as reported in the consolidated transaction reporting system.
| High | Low | |||||||
2015 | ||||||||
First Quarter | $ | 73.00 | $ | 52.01 | ||||
Second Quarter | 59.80 | 50.01 | ||||||
Third Quarter | 77.00 | 50.79 | ||||||
Fourth Quarter | 72.53 | 45.31 | ||||||
2014 | ||||||||
First Quarter | $ | 61.56 | $ | 44.01 | ||||
Second Quarter | 63.95 | 48.56 | ||||||
Third Quarter | 69.10 | 59.53 | ||||||
Fourth Quarter | 77.53 | 46.55 | ||||||
The above quotations reflect inter-dealer prices, without retail mark-up, mark-down or commissions, and may not represent actual transactions.
As of March 28, 2016,April 4, 2024 there were 463200 registered holders of the common stock.
No
We have not paid any dividends have been declared or paid during the past twothree most recent fiscal years on our common stock.or any subsequent interim period, and we do not intend to pay any cash dividends in the foreseeable future. Provisions of our line of credit agreement restrict our ability to pay dividends. Such dividends may be declared out of funds legally available therefore, when and as declared by our Board of Directors.
Issuer Sales and Purchases of Equity Securities
There were no sales of equity securities by the Company during the period covered by this report. The following table details the Company’s purchases of shares for the three months ended December 31, 2023.
2023 Month | Total Number of Purchased | Average Price | Maximum Number of Shares That May Yet Be Program at Month-End (1) | |||||||||
October | 7,000 | $ | 110.43 | 275,044 | ||||||||
November | 1,000 | $ | 107.39 | 274,044 | ||||||||
December | 400 | $ | 109.35 | 273,644 | ||||||||
Total/Average | 8,400 | $ | 100.02 | |||||||||
(1)In December 1993, we announced that the Board of Directors authorized a stock repurchase program whereby we may purchase outstanding shares of the common stock from time-to-time, in open market transactions or negotiated sales. On October 31, 2012, June 13, 2018 and June 7, 2023, the Board of Directors of the Company approved an additional 500,000, 200,000 and 300,000 shares respectively, of the Company’s stock to be included in the stock repurchase program. A total of 3,500,0004,000,000 shares have been authorized to date under this program. Through December 31, 2015,2023, a total of 3,241,7723,726,356 shares have been repurchased under this program for $54,036,636$89,987,612 at an average price of $16.69$24.15 per share. The stock repurchase program has no specific term. 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.
2015 Month | Number of Shares | Average Price Paid per share | Maximum Number of Shares that May Yet Be Purchased Under The Program at Month-End | |||||||||
January | 15,980 | $ | 68.73 | 270,968 | ||||||||
February | 774 | 59.34 | 270,194 | |||||||||
March | 2,506 | 54.00 | 267,688 | |||||||||
April | 50 | 59.40 | 267,638 | |||||||||
May | 226 | 57.52 | 267,412 | |||||||||
June | 379 | 56.02 | 267,033 | |||||||||
July | 695 | 56.56 | 266,338 | |||||||||
August | 316 | 55.91 | 266,022 | |||||||||
September | 4,404 | 64.74 | 261,618 | |||||||||
October | 858 | 69.19 | 260,760 | |||||||||
November | 197 | 59.11 | 260,563 | |||||||||
December | 2,335 | 52.46 | 258,228 | |||||||||
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Total / Average | 28,720 | $ | 64.50 | |||||||||
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We are a smaller reporting company and therefore no response is required pursuant to this Item.
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Item 6. | RESERVED |
Item 7. |
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The following discussion is intended to assist you in understanding our results of operations and our present financial condition. Our Consolidated Financial Statements and the accompanying Notes to the Consolidated Financial Statements included elsewhere in this Report contains additional information that should be referred to when reviewing this material. Our subsidiaries are listed in Note 1 to the Consolidated Financial Statements.
Overview:
We are an independent oil and natural gas company engaged in acquiring, developing, and producing oil and natural gas. We presently own producing and non-producing properties located primarily in Texas, Oklahoma, West Virginia, New Mexico, Colorado and Louisiana.Oklahoma. In addition, we own a substantial amount of well servicing equipment. All of our oil and gas properties and interests are located in the United States. Assets in our principal focus areas include mature properties with long-lived reserves and significant development opportunities as well as newer properties with development and exploration potential. We believe our balanced portfolio of assets and our ongoing hedging program position us well for both the current commodity price environment and future potential upside as we develop our attractive resource opportunities. Our primary sources of liquidity are cash generated from our operations and our credit facility.
We attempt to assume the position of operator in all acquisitions of producing properties and will continue to evaluate prospects for leasehold acquisitions and for exploration and development operations in areas in which we own interests. We continue to actively pursue the acquisition of producing properties. In order toTo 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 so as to build stockholder value through consistent growth in our oil and gas reserve base on a cost-efficient basis.
Our cash flows depend on many factors, including the price of oil and gas, the success of our acquisition and drilling activities and the operational performance of our producing properties. We use derivative instruments to manage our commodity price risk. This practice may prevent us from receiving the full advantage of any increases in oil and gas prices above the maximum fixed amount specified in the derivative agreements and subjects us to the credit risk of the counterparties to such agreements. Since all of our derivative contracts are accounted for under mark-to-market accounting, we expect continued volatility in gains and losses on mark-to-market derivative contracts in our consolidated statement of operations as changes occur in the NYMEX price indices.
Market Conditions and Commodity Prices:
Our financial results depend on many factors, particularly the price of natural gas and crude oil and our ability to market our production on economically attractive terms. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by weather conditions, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. In addition, our realized prices are further impacted by our derivative and hedging activities. We derive our revenue and cash flow principally from the sale of oil, natural gas and NGLs. As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil, natural gas and NGLs. We sell our oil and natural gas on the open market at prevailing market prices or through forward delivery contracts. Because some of our operations are located outside major markets, we are directly impacted by regional prices regardless of Henry Hub, WTI or other major market pricing. The market price for oil, natural gas and NGLs is dictated by supply and demand; consequently, we cannot accurately predict future commodityor control the price we may receive for our oil, natural gas and NGLs. Index prices for oil, natural gas, and therefore,NGLs have improved since the lows of 2020 however we expect prices to remain volatile and consequently cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our capital program, production volumes or revenues. Location differentials have increased in certain regions, such as in the Appalachian region, resulting in further declines in natural gas prices. We expect natural gas and crude oil prices to remain volatile. In addition to production volumes and commodity prices, finding and developing sufficient amounts of natural gas and crude oil reserves at economical costs are critical to our long-term success.
Critical Accounting Estimates:
Proved Oil and Gas Reserves
Proved oil and gas reserves directly impact financial accounting estimates, including depreciation, depletion and amortization. Proved reserves represent estimated quantities of natural gas, crude oil, condensate, and natural gas liquids that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. The process of estimating quantities of proved oil and gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but
not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time.
Depreciation, Depletion and Amortization for Oil and Gas Properties
The quantities of estimated proved oil and gas reserves are a significant component of our calculation of depletion expense and revisions in such estimates may alter the rate of future expense. Holding all other factors constant, if reserves were revised upward or downward, earnings would increase or decrease respectively. Depreciation, depletion and amortization of the cost of proved oil and gas properties are calculated using the unit-of-production method. The reserve base used to calculate depletion, depreciation or amortization is the sum of proved developed reserves and proved undeveloped reserves for leasehold acquisition costs and the cost to acquire proved properties. The reserve base includes only proved developed reserves for lease and well equipment costs, which include development costs and successful exploration drilling costs. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account.
Asset Retirement Obligation (ARO):
The Company has significant obligations to remove tangible equipment and restore land at the end of oil and gas production operations. The Company’s removal and restoration obligations are primarily associated with plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public relations considerations. ARO associated with retiring tangible long-lived assets is recognized as a liability in the period in which the legal obligation is incurred and becomes determinable. The liability is offset by a corresponding increase in the underlying asset. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with the Company’s oil and gas properties. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value
Liquidity and Capital Resources:
Our primary sources of liquidity are cash generated from our operations, through our producing oil and gas properties, field services business and sales of acreage, and available capacity under our revolving credit facility.
Net cash provided by operating activities for the year ended December 31, 20152023 was $21$109.0 million compared to $56$33.1 million in the prior year. Excluding the effects of significant unforeseen expenses or other income, our cash flow from operations fluctuates primarily because of variations in oil and gas production and prices or changes in working capital accounts. Our oil and gas production will vary based on actual well performance but may be curtailed due to factors beyond our control.
Our realized oil and gas prices vary due to world political events, supply and demand of products, product storage levels, and weather patterns. We sell the vast majority of our production at spot market prices. Accordingly, product price volatility will affect our cash flow from operations. To mitigate price volatility, we sometimes lock in prices for some portion of our production through the use of derivatives.
If our exploratory drilling results in significant new discoveries, we will have to expend additional capital to finance the completion, development, and potential additional opportunities generated by our success. We believe that, because of the additional reserves resulting from the successful wells and our record of reserve growth in recent years, we will be able to access sufficient additional capital through bank financing.
Maintaining a strong balance sheet and ample liquidity are key components of our business strategy. For 2024, we will continue our focus on preserving financial flexibility and liquidity as we manage the risks facing our industry. Our 2024 capital budget is reflective of commodity prices and has been established based on an expectation of available cash flows, with any cash flow deficiencies expected to be funded by borrowings under our revolving credit facility. As of March 1, 2016,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.
The Company maintains a Credit Agreement with a maturity date of June 1, 2026, providing for a credit facility totaling $250$300 million, with a borrowing base of $95$85 million. As of March 31, 2024, the Company had $4 million in outstanding borrowings and $81 million in availability under this facility. The bank reviews the borrowing base semi-annually and, at theirits discretion, may decrease or propose an increase to the borrowing base relative to a redeterminedre-determined estimate of proved oil and gas reserves. The next borrowing base review is scheduled for May 2024. 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 redeterminedre-determined borrowing base.
Maintaining
Our credit agreement requires us to hedge a strong balance sheet and ample liquidity are key componentsportion of our business strategy. For 2016, we will continue our focus on preserving financial flexibility and ample liquidityproduction as we manageforecasted for the risks facing our industry. Our 2016 capital budget is reflective of decreased 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. We are activelyPDP reserves included in discussions with financial partners for funding to develop our asset base and, if required, pay down our revolving credit facility should our borrowing base become limitedreview engineering reports. The credit agreement requires that as of the last day of any fiscal quarter, if the borrowing base utilization percentage on such a date is less than the 15%, then the borrower shall not be required to enter into any swap agreements. As of the quarter ended December 31, 2023, the Company had no outstanding borrowings. Accordingly, the Company had no swap agreements in place for oil and natural gas.
The Company’s activities include development and exploratory drilling. Our strategy is to develop a balanced portfolio of drilling prospects that includes lower risk wells with a high probability of success and higher risk wells with greater economic potential. Horizontal development of our resource base provides superior returns relative to vertical development due to the deteriorationability of commodity prices.each horizontal wellbore to come in contact with a greater volume of reservoir rock across a greater distance, more efficiently draining the reserves with less infrastructure and thus at a lower cost per acre.
Due
In 2023, including 20 wells spud in the fourth quarter of 2023, the Company participated with five operators in 35 wells: 32 of these are located in West Texas and three are located in Oklahoma. The Company invested approximately $91 million in these wells, including in their production facilities, almost all attributable to wells drilled and completed in West Texas where we are focused on horizontal development of various proven pay intervals in the uncertaintyWolfcamp and Spraberry formations. On December 31, 2023, we had 12 wells completed that were all brought into production in January of financing availability we have removed all but one PUD location from our yearend reserve report in accordance with the SEC rules governing the scheduling2024. In addition to $7.9 million of the drilling of PUD reserves within 5 years. We expect to continue development of those reserves when our borrowing base is redetermined and, if required, we have secured$91 million invested in these wells in 2023, the Company had an additional sources of financing. The one PUD included$15.5 million investment in our reportthese 12 wells. Also at year-end 2023, the Company was drilled in the first quarterprocess of 2016 as part of our joint venture with Apache Corporationdrilling and completing 34 wells in Upton County, Texas.
We began our West Texas Upton County horizontal drilling program during 2015that carry an expense of $80.6 million, and through the first quarter of 2016 we have drilled 4 wellsplanning for a 50% participation in this phase. Discussions with our joint venture partner in that program, Apache Corporation, indicate that includingan additional phases of development in the program will result in approximately 60 horizontal wells being drilled at a cost of approximately $470 million. We own various interests, ranging from 16% up to 50% interest in the lands to be developed in the program, and expect our share of these capital expenditures to be approximately $120 million. The actual number of12 wells to be drilled and the timingin 2024 that will require an investment of the drilling may vary based on commodity market conditions. Currentlyapproximately $43 million. In total, the Company expects to invest $140 million in 54 wells in 2024 and, Apache have agreed until oil and gas prices recoverin 2025, to limit drilling to thoseinvest $95 million in an additional 23 wells required to maintain our acreage position. Apache drilling plans indicated two of these wells will be drilled later this year at a cost of $12 million, of which our share is $6 million. These two wells meet the definition of proved undeveloped reserves however they were not included in our yearend reserve report because we have not confirmed our financing for those wells at this time.
During 2023, to supplement cash flow and finance our future drilling programs, the firstCompany sold 368 net mineral acres as well as 7.8 surface acres in Midland County, Texas receiving gross proceeds of $436,050 and recognizing a gain of $47,000.
In the second quarter of 2016 we commenced our2023, the Company acquired 55 net acres in the South Stiles area of Reagan County, Texas for $605,000, and in a separate agreement also in Reagan County, the Company sold 320 non-core acres for proceeds of $6,000,000. In addition, the Company sold 36.51% interest in one well in Midland County, Texas for proceeds of $60,000.
In the third quarter of 2023, the Company sold a non-core 38.25-acre leasehold tract in Martin County, Texas horizontal drilling program, two wells have been drilledfor proceeds of $899,000 and cased, at a cost of $8.3 million of which our share is $8.1 million, and they are currently awaiting completion. These wells did not meet the definition of proved undeveloped reserves and therefore are not included as PUDs in our yearend reserve report. We maintain an acreage position of over 26,000 gross (16,500 net)sold 3 surface acres in Liberty County, Texas for net proceeds of $37,053. Also in the third quarter, in various counties of Oklahoma, the Company divested its interest in 39 wells, reducing its future plugging liability by approximately $1.5 million. Effective July 1, 2023, the Company acquired the operations of 36 wells from DE Permian Basinand 50% of DE Permian’s original ownership in West Texas, primarilysuch wells. In addition, in Reagan Upton, Martin and Midland counties. We believe this acreage has significant resource potential inCounty, Texas, the Spraberry and Wolfcamp intervals for drilling opportunities. Our Oklahoma horizontal development is primarily in Grant and Canadian counties where we have approximately 6,450Company acquired 114.52 net acres which we believe have significant resource potential based on our drilling resultsfrom DE Permian for $1,700,853 and those of offset operators.assigned to them 203.23 net acres.
During
In the firstfourth quarter of 2016 we have farmed out certain non-core acreage2023, the Company sold 136 surface acres in exchangeOklahoma for net proceeds of $306,000 and in Midland Texas sold 9.35 net acres for proceeds of $280,423.
Proceeds from these sales in 2023, along with our cash and a royalty or working interest in both West Texas and Oklahoma. Proceeds received under these agreements are $3.7 million with an additional $1.0 million expected inflow, were used to eliminate the next 45 days.
AsCompany’s outstanding bank debt as of March 1, 2016,31, 2023. As noted above, as of March 31, 2024, the Company has $9.06had $4 million outstanding on our equipment financing facilities which are secured by substantially all of our field service equipment. borrowings and $81 million in availability under this facility.
The majority of our capital spending is discretionary, and the ultimate level of expenditures will be dependent on our assessment of the oil and gas business environment, the number and quality of oil and gas prospects available, the market for oilfield services, and oil and gas business opportunities in general.
The Company has in place both a stock repurchase program in place, spending under this program in 2023 and a limited partnership interest repurchase program. Spending under these programs in 20152022 was $2.26 million.$7.5 million and $7.4 million, respectively. The Company expects continued spending under these programsthe stock repurchase program in 2016.2024.
Results of Operations:Operations
20152023 and 20142022 Compared
We reported a net lossincome of $28.1 million for 2015 of $12.8 million,2023, or $ 5.53$15.19 per share, compared to $48.7 million, or $24.91 per share for 2022. The current year net income for 2014 of $27.05 million, or $11.45 per share. Gains on derivative instruments substantially increased related to the decrease inreflects production increases offset by commodity prices while such price declines reduced oil and gas sales compared to 2014. The remaining decrease was attributed to the decrease in the net field service income and increases in depreciation and depletion expenses.decreases. The significant components of net income and expense are discussed below.
Oil, NGL and gas sales decreased $45.4$16.4 million, or 61.7% from $91.0513.19% to $107.7 million for the year ended December 31, 2014 to $45.632023 from $124.1 million for the year ended December 31, 2015.2022. 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 decreased an average of $40.99$19.86 per barrel, or 44%20.54% on crude oil, decreased an average of $16.06 per barrel, or 44.99% on NGL and increased $2.61decreased $3.62 per Mcf, or 46.4%65.34% on natural gas during 20152023 as compared to 2014.2022.
Our crude oil production decreasedincreased by 39,000205,000 barrels, or 6.8% from 759,00021.83% to 1,144,000 barrels for the year ended December 31, 2014 to 720,0002023 from 939,000 barrels for the year ended December 31, 2015.2022. Our NGL production increased by 189,000 or 45.32% to 606,000 for the year ended December 31, 2023 from 417,000 barrels for the year ended December 31, 2022. Our natural gas production decreasedincreased by 45802 MMcf, or 1.3% from 4,74124.12% to 4,127 MMcf for the year ended December 31, 2014 to 4,6962023 from 3,325 MMcf for the year ended December 31, 2015.2022. The decreasechanges in crude oil, NGL and natural gas production volumes are a result of new wells placed in production offset by the natural decline of existing properties offset by our continued drilling success in the West Texas and Oklahoma regions as we place new wells into production.properties.
The following table summarizes the primary components of production volumes and average sales prices realized for the years ended December 31, 20152023 and 20142022 (excluding realized gains and losses from derivatives).
| Year Ended December 31, | Increase (Decrease) | Years ended | Increase / | Increase / | ||||||||||||||||||||||||||||
| 2015 | 2014 | Amount | Percent | 2023 | 2022 | (Decrease) | (Decrease) | |||||||||||||||||||||||||
Barrels of Oil Produced | 720,000 | 759,000 | (39,000 | ) | (6.8 | )% | 1,144,000 | 939,000 | 205,000 | 21.83 | % | |||||||||||||||||||||
Average Price Received (excluding the impact of derivatives) | $ | 45.74 | $ | 86.73 | $ | (40.99 | ) | (44.0 | )% | |||||||||||||||||||||||
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Average Price Received | $ | 76.84 | $ | 96.70 | $ | (19.86 | ) | (20.54 | )% | |||||||||||||||||||||||
Oil Revenue (In 000’s) | $ | 32,923 | $ | 65,824 | $ | (32,901 | ) | (61.3 | )% | $ | 87,906 | $ | 90,803 | $ | (2,897 | ) | (3.19 | )% | ||||||||||||||
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Mcf of Gas Produced | 4,696,000 | 4,741,000 | (45,000 | ) | (1.3 | )% | ||||||||||||||||||||||||||
Average Price Received (excluding the impact of derivatives) | $ | 2.71 | $ | 5.32 | $ | (2.61 | ) | (46.4 | )% | |||||||||||||||||||||||
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Mcf of Gas Sold | 4,127,000 | 3,325,000 | 802,000 | 24.12 | % | |||||||||||||||||||||||||||
Average Price Received | $ | 1.92 | $ | 5.54 | $ | (3.62 | ) | (65.34 | )% | |||||||||||||||||||||||
Gas Revenue (In 000’s) | $ | 12,709 | $ | 25,221 | $ | (12,512 | ) | (62.6 | )% | $ | 7,935 | $ | 18,428 | $ | (10,493 | ) | (56.94 | )% | ||||||||||||||
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Barrels of Natural Gas Liquids Sold | 606,000 | 417,000 | 189,000 | 45.32 | % | |||||||||||||||||||||||||||
Average Price Received | $ | 19.64 | $ | 35.70 | $ | (16.06 | ) | (44.99 | )% | |||||||||||||||||||||||
Natural Gas Liquids Revenue (In 000’s) | $ | 11,901 | $ | 14,887 | $ | (2,986 | ) | (20.06 | )% | |||||||||||||||||||||||
Total Oil & Gas Revenue (In 000’s) | $ | 45,632 | $ | 91,045 | $ | (45,413 | ) | (61.7 | )% | $ | 107,742 | $ | 124,118 | $ | (16,376 | ) | (13.19 | )% | ||||||||||||||
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Realized net gains (losses) on derivative instruments, netOil, Natural Gas and NGL Derivatives include net gains of $18.1 million and $3.0 million on the settlements of crude oil and natural gas derivatives, respectively for the year ended December 31, 2015. During 2014 this item included net gains of $0.6 million and net losses of $0.5 million on the settlements of crude oil and natural gas derivatives, respectively for the year ended December 31, 2014. During 2014, we unwound and monetized natural gas swaps with original settlement dates from January 2015 through
December 2015 for net proceeds of $0.28 million. In addition we unwound and monetized crude oil swaps with original settlement dates from January 2016 through December 2016 for net proceeds of $0.70 million. The $0.98 million in gains associated with these early settlement transactions is included in realized gain on derivative instruments for the year ended December 31, 2014.
Oil and gas prices received including the impact of derivatives were:
Year Ended December 31, | Increase (Decrease) | |||||||||||||||
| 2015 | 2014 | Amount | Percent | |||||||||||||
Oil Price | $ | 70.93 | $ | 86.67 | $ | (15.74 | ) | (18.16 | )% | |||||||
Gas Price | $ | 3.35 | $ | 5.15 | $ | (1.80 | ) | (34.97 | )% | |||||||
We do not apply hedge accounting to any of our commodity based derivatives, thus changes in the fair market value of commodity contracts held at the end of a reported period, referred to as mark-to-market adjustments, are recognized as unrealized gains and losses in the accompanying condensed consolidated statements of operations. As oil and natural gas prices remain volatile, mark-to-market accounting treatment creates volatility in our revenues. During
The following table summarizes the results of our derivative instruments for the years ended December 2023 and 2022:
Years ended | ||||||||
2023 | 2022 | |||||||
Oil derivatives - realized gains (losses) | $ | 179 | $ | (12,101 | ) | |||
Oil derivatives – unrealized gains | -- | 3,713 | ||||||
Total gains (losses) on oil derivatives | $ | 179 | $ | (8,388 | ) | |||
Natural gas derivatives – realized gains (losses) | 235 | (4,543 | ) | |||||
Natural gas derivatives – unrealized gains | -- | 892 | ||||||
Total gains (losses) on natural gas derivatives | $ | 235 | $ | (3,651 | ) | |||
Total gains (losses) on oil and natural gas | $ | 414 | $ | (12,039 | ) | |||
Prices received for the years ended December 31, 2023 and 2022, respectively, including the impact of derivatives were:
2023 | 2022 | Increase / | Increase / | |||||||||||||
Oil Price | $ | 76.33 | $ | 87.77 | $ | (11.44 | ) | (13.03 | )% | |||||||
Gas Price | $ | 1.93 | $ | 4.44 | $ | (2.51 | ) | (56.53 | )% | |||||||
NGL Price | $ | 19.64 | $ | 35.70 | $ | (16.06 | ) | (44.99 | )% | |||||||
Oil and gas production expense increased $1.0 million, or 4.0% to 3.11% for the year ended December 31, 2015, we recognized net unrealized losses of $14.6 million associated with crude oil fixed swaps and collars and $2.3 million associated with natural gas fixed swap contracts due to market fluctuations in natural gas and crude oil futures market prices between January 1, 2015 and December 31, 2015.
Field service income decreased $5.4 million, or 20.5%2023 from $26.27$31.7 million for the year ended December 31, 20142022. These changes reflect the cost savings related to $20.88wells that have been plugged offset by rising service costs and additional costs related to the new wells that have been placed on production.
Field service income increased $2.4 million or 18.5% to $15.4 million for the year ended December 31, 2015. We reduced rates on our workover rig and hot oiler services during 2015 in response to the reduced commodity prices. This decrease was offset by increases in our SWD income related to increased utilization of the pipeline and capacity upgrades added during 2014 and 2015.
Lease operating expense decreased $8.8 million, or 19.9%2023 from $43.97$13.0 million for the year ended December 31, 20142022. Workover rig services, hot oil treatments, saltwater hauling and disposal represent the bulk of our field service operations. These changes reflect the variance in equipment utilization and service rates during these periods.
Field service expense increased $0.6 million, or 5.4% to $35.21$11.7 million for the year ended December 31, 2015. This decrease was largely due to cost reductions2023 from suppliers and improved operational efficiencies, including reduced SWD expenses reflecting the switch from hauling to piping salt water to SWD facilities.
Field service expense decreased $3.5 million, or 16.7% from $21.19$11.1 million for the year ended December 31, 20142022. Field service expenses primarily consist of wages and vehicle operating expenses. The changes reflect the variance in equipment utilization during the periods represented.
Depreciation, depletion, and amortization increased $3.6 million, or 13.1% to $17.6$31 million for the year ended December 31, 2015. Field service expenses primarily consist of salaries and vehicle operating expenses which have been reduced during 2015 in response to falling rates and utilization of our equipment services.
Depreciation, depletion, amortization and accretion on discounted liabilities increased $5.7 million, or 18%2023 from $25.86$27.4 million for the year ended December 31, 2014 to $31.6 million for the year ended December 31, 2015. This increase in2022. The DD&A expense is primarily attributable to increased depletion expenses related to new wells coming on line from the recent drilling successour properties in West Texas and Oklahoma, combined with reductions in proved reserves as a resultreflecting the addition of new properties offset by the decline in commodity prices.declining cost basis of existing properties.
General and administrative expense decreased $2.19$4.6 million, or 15.2% from $14.4622.7% to $15.6 million for the year ended December 31, 2014 to $12.272023 from $20.2 million for the year ended December 31, 20152021. These changes are primarily related to reductions in personnel costs, including salariesemployee compensation and employee related taxes and insurance.benefits.
Gain on sale and exchange of assets of $1.38$8.9 million for the year ended December 31, 20152023 consists of sales of net mineral and $6.12surface acres in various locations in Texas and Oklahoma. The $31.8 million for the year ended December 31, 20142022 consists principally of sales of non-producingdeep rights in undeveloped acreage and non-core oil and gas interests and non-essential field service equipment.in West Texas.
Interest expenseexpense decreased $0.39$0.4 million, or 9.7% from $4.0241.0% to $0.5 million for the year ended December 31, 2014 to $3.632023 from $0.9 million for the year ended December 31, 2015.2022. This decrease relatesreflects the increase in rates combined with reduced borrowings under our revolving credit agreement
Tax expense of $6.1 million and $10.3 million were recorded for the years ended December 31, 2023 and 2022, respectively. The change in our income tax provision was primarily due to athe decrease in average debt outstanding during 2015 as compared to 2014 combined with a decrease in weighted average interest rates during the 2015 periods. The average interest rate paid on outstanding bank borrowings subject to interest during 2015 and 2014 were 3.44% and 3.53%, respectively. As of December 31, 2015 and 2014, the total outstanding borrowings were $95.6 million and $101.4 million, respectively.
A tax benefit of $6.65 million, or an effective rate of 34% was recordedpre-tax income for the year ended December 31, 2015, verses a provision of $13.84 million and an effective rate of 34% for the year ended December 31, 2014.
Item 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. |
We are a smaller reporting company and therefore no response is required pursuant to this Item.
Item 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. |
The consolidated financial statements and supplementary information included in this Report are described in the Index to Consolidated Financial Statements at Page F-1 of this Report.
Item 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. |
None.
Item 9A. | CONTROLS AND PROCEDURES. |
As of the end of the period covered by this Annual Report on Form 10-K, our principal executive officer and principal financial officer have evaluated the effectiveness of our “disclosure controls and procedures” (“Disclosure Controls”). Disclosure Controls, as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), are procedures that are designed with the objective of ensuring that information required to be disclosed in our reports filed under the Exchange Act, such as this Annual Report, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Disclosure Controls are also designed with the objective of ensuring that such information is accumulated and communicated to our management, including the chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.
Our management, including the chief executive officer and chief financial officer, does not expect that our Disclosure Controls will prevent all error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions.
Members of our management, including our chief executive officer and chief financial officer, have evaluated the effectiveness of our disclosure controls and procedures, as defined by paragraph (e) of Exchange Act Rules 13a-15 or 15d-15, as of December 31, 2015,2023 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, 2015.2023.
Management’s
Management’s Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Our internal control over financial reporting is a process designed to provide reasonable assurance that assets are safeguarded against loss from unauthorized use or disposition, transactions are executed in accordance with appropriate management authorization and accounting records are reliable for the preparation of financial statements in accordance with U.S. generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2015.2023. Management based this assessment on criteria for effective internal control over financial reporting described in “Internal Control—Control – Integrated Framework (2013)” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management’s assessment included an evaluation of the design of our internal control over financial reporting and testing of the operational effectiveness of its internal control over financial reporting. Management reviewed the results of its assessment with the Audit Committee of our Board of Directors.
Based on
As a result of this assessment, management believesconcluded that, the Company maintained effectiveas of December 31, 2023, our internal control over financial reporting aswas effective in providing reasonable assurance regarding the reliability of December 31, 2015.
financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. This Annual Report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this Annual Report.
There have been no changes in our internal controls over financial reporting during the fourth fiscal quarter ended December 31, 20152023 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.
Item 9B. | OTHER INFORMATION. |
None.
None.
Item 9C. | DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS. |
Not applicable.
PART III
Item 10. | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE. |
Information relating to the Company’s Directors, nominees for Directors and executive officers will be included in the Company’s definitive proxy statement relating the Company’s Annual Meeting of Stockholders to be held in May, 2016 which will be filed with the U.S. Securities and Exchange Commission within 120 days of December 31, 2015,June 5, 2024, and which is incorporated herein by reference.
Code of Conduct and Ethics
We have adopted a Code of Business Ethics and Conduct (the “Code”) that applies to all officers and employees. The Code is publicly available under the governance tab of our website at www.primeenergy.com. Any amendments to, or waivers of, the Code with respect to our principal executive officer, principal financial officer or principal accounting officer or controller, or persons performing similar functions, will be disclosed on our website within four business days following the date of the amendment or waiver. Copies of the Code may also be requested in print by writing to PrimeEnergy Resources Corporation, 9821 Katy Freeway, Suite 1050, Houston, TX 77024.
Item 11. | EXECUTIVE COMPENSATION. |
Information relating to executive compensation will be included in the Company’s definitive proxy statement relating to the Company’s Annual Meeting of Stockholders to be held in May, 2016, which will be filed with the U. S. Securities and Exchange Commission within 120 days of December 31, 2015,June 5, 2024, and which is incorporated herein by reference.
Item 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS. |
Information relating to security ownership of certain beneficial owners and management will be included in the Company’s definitive proxy statement relating to the Company’s Annual Meeting of Stockholders to be held in May, 2016, which will be filed with the U. S. Securities and Exchange Commission within 120 days of December 31, 2015,June 5, 2024, and which is incorporated herein by reference.
Item 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE. |
Information relating to certain transactions by Directors and executive officers of the Company will be included in the Company’s definitive proxy statement relating to the Company’s Annual Meeting of Stockholders to be held in May, 2016, which will be filed with the U. S. Securities and Exchange Commission within 120 days of December 31, 2015,June 5, 2024, and which is incorporated herein by reference.
Item 14. | PRINCIPAL ACCOUNTANT FEES AND SERVICES. |
Information relating to principal accountant fees and services will be included in the Company’s definitive proxy statement relating to the Company’s Annual Meeting of Stockholders to be held in May, 2016, which will be filed with the U. S. Securities and Exchange Commission within 120 days of December 31, 2015,June 5, 2024, and which is incorporated herein by reference.
PART IV
Item 15. | EXHIBITS AND FINANCIAL STATEMENT SCHEDULES. |
The following documents are filed as part of this Report:
1. | Financial statements (Index to Consolidated Financial Statements at page F-1 of this Report) |
2. | Financial Statement Schedules |
3. | Exhibits: |
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3.2 | ||
4.1 | ||
10.18 | ||
10.22.6 | ||
10.22.6.1 | ||
10.22.6.2 | ||
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21 | ||
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23 | ||
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31.1 | ||
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31.2 | ||
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32.1 | ||
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32.2 | ||
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97.1 | PrimeEnergy Resources Corporation Compensation Recoupment (CLAWBACK) Policy, (filed herewith). | |
99.1 | Summary Reserve Report dated March | |
101.INS | Inline XBRL (eXtensible Business Reporting Language) Instance Document (filed herewith) | |
101.SCH | Inline XBRL Taxonomy Extension Schema Document (filed herewith) | |
101.CAL | Inline XBRL Taxonomy Extension Calculation Linkbase Document (filed herewith) | |
101.DEF | Inline XBRL Taxonomy Extension Definition Linkbase Document (filed herewith) | |
101.LAB | Inline XBRL Taxonomy Extension Label Linkbase Document (filed herewith) | |
101.PRE | Inline XBRL Taxonomy Extension Presentation Linkbase Document (filed herewith) | |
104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) | |
Item16. FORM 10-K SUMMARY.
None.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 7th15th day of April, 20162024.
PrimeEnergy Resources Corporation | |||
| |||
By: | /s/ Charles E. Drimal, Jr. | ||
Charles E. Drimal, Jr. | |||
Chairman, Chief Executive Officer and President | |||
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated and on the 7th8th, day of April, 2016.2024.
/s/ Charles E. Drimal, Jr. | Chairman, Chief Executive Officer and President; | |||||
| Charles E. Drimal, Jr. | The Principal Executive Officer | |||||
/s/ Beverly A. Cummings | Director, Executive Vice President and Treasurer; | |||||
| Beverly A. Cummings | The Principal Financial Officer | |||||
/ | Director | /s/ | Director | ||||||
| Clint Hurt | Thomas S. T. Gimbel | ||||||||
/s/ H. | Director |
| |||||||
| H. Gifford Fong | |||||||||
/s/ THOMAS S.T. GIMBEL
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
F-2 | ||||
Financial Statements | ||||
Consolidated Balance | F-4 | |||
Consolidated | ||||
| F-5 | |||
Consolidated | F-6 | |||
Consolidated | F-7 | |||
F-8 | ||||
Supplementary Information: | ||||
F-19 | ||||
F-19 | ||||
F-19 | ||||
F-20 | ||||
Reserve Quantity Information, years ended December 31, | F-21 | |||
F-21 | ||||
F-22 | ||||
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To theThe Board of Directors and Stockholders of
PrimeEnergy Resources Corporation and Subsidiaries:Subsidiaries
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of PrimeEnergy Resources Corporation and Subsidiaries (the Company)“Company”) as of December 31, 20152023 and 2014, and2022, the related consolidated statements of operations, comprehensive income, equity and cash flows for each of the years then ended. The Company’s management is responsible for these financial statements. Our responsibility isended, and the related notes (collectively referred to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance withas the standards of the Public Company Accounting Oversight Board (United States)“financial statements”). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of PrimeEnergy Corporation and Subsidiariesthe Company as of December 31, 20152023 and 2014,2022, and the results of its operations and its cash flows for each of the years then ended, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Depreciation, Depletion and Amortization of Oil and Gas Properties
Critical Audit Matter Description
At December 31, 2023, the carrying value of the Company’s oil and gas properties was $252.9 million, and depreciation, depletion and amortization (“DD&A”) expense was $31.0 million for the year then ended. As described in Note 1, under the successful efforts method of accounting, capitalized costs of proved properties are depleted using the units of production method based on proved reserves, as estimated by independent petroleum engineers. Proved reserve estimates are impacted by various inputs, including historical production, oil and gas price assumptions, and future operating and capital cost assumptions, among other factors. Because of the complexity involved in estimating oil and gas reserves, the Company utilized independent petroleum engineers for the year ended December 31, 2023.
Auditing the Company’s DD&A calculations is complex because of the use of independent petroleum engineers and the evaluation of management’s determination of the inputs described above used by the engineers in estimating oil and gas reserves.
How the Critical Audit Matter was Addressed in the Audit
Our audit procedures related to the evaluation of DD&A of oil and gas properties included the following, among others:
● | We obtained an understanding and evaluated the design of the Company’s controls over its process to calculate DD&A, including management’s controls over the completeness and accuracy of the financial data utilized by the engineers in estimating oil and gas reserves. |
● | We evaluated the professional qualifications and objectivity of the Company’s independent petroleum engineers responsible for the preparation of the proved oil and gas reserve estimates for select properties. |
● | We evaluated the methodologies and assumptions utilized by the Company’s independent engineers to ensure they were reasonable and in accordance with industry standards. |
● | We compared the Company’s recent production with its reserve estimates for properties that have significant production or significant reserve quantities and inquired of disproportionate ratios that did not align with our expectations. |
● | We tested the mathematical accuracy of the DD&A calculations, including comparing the oil and gas reserve amounts used in the calculations to the Company’s reserve reports. |
Accounting for Asset Retirement Obligations
Critical Audit Matter Description
At December 31, 2023, the asset retirement obligation (“ARO”) balance totaled $15.2 million. As further described in Note 1, the Company’s ARO primarily represents the estimated present value of the amount the Company will incur to plug, abandon, and remediate producing properties at the end of their productive lives, in accordance with applicable state laws. The Company’s liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive life of wells and a risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Because of the subjectivity of assumptions and the relatively long life of most of the Company’s wells, the costs to ultimately retire the wells may vary significantly from previous estimates.
Auditing the Company’s ARO is complex and highly judgmental because of the significant estimation by management in determining the obligation. In particular, the estimate was sensitive to significant subjective assumptions such as retirement cost estimates and the estimated timing of settlements, which are both affected by expectations about future market and economic conditions.
How the Critical Audit Matter was Addressed in the Audit
Our audit procedures related to the evaluation of the accounting for the ARO included the following, among others:
● | We obtained an understanding and evaluated the design of the Company’s internal controls over its ARO estimation process, including management’s review of the significant assumptions that have a material effect on the determination of the obligations. Based on our evaluation, we designed our audit procedures to include, among others, assessing the significant assumptions and inputs used in the valuation, such as retirement cost estimates and timing of settlement assumptions. |
● | We compared the ARO against historical results, reviewed the reasonableness of the discount rate utilized in the estimate, considered the reasonableness of the current and long-term portion of the obligation by comparing the accretion expense trends, and considered the completeness of the properties included in the estimate by comparing to the Company’s reserve reports. |
/s/ Grassi & Co., CPAs, P.C.
GRASSI & CO., CPAs, P.C.
New York,
We have served as the Company's auditor since 1989.
Jericho, New York
March 30, 2016
PRIMEENERGY RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETSHEETS
(Thousands of dollars)dollars, except share data)
| As of December 31, | As of December 31, | |||||||||||||||
| 2015 | 2014 | 2023 | 2022 | |||||||||||||
ASSETS | ||||||||||||||||
Current Assets | ||||||||||||||||
Cash and cash equivalents | $ | 9,750 | $ | 9,209 | $ | 11,061 | $ | 26,543 | ||||||||
Restricted cash and cash equivalents | 3,513 | 3,877 | ||||||||||||||
Accounts receivable, net | 9,543 | 12,315 | 20,301 | 12,147 | ||||||||||||
Prepaid obligations | 619 | 877 | 376 | 32,839 | ||||||||||||
Derivative contracts | — | 16,914 | ||||||||||||||
Deferred Income taxes | 534 | — | ||||||||||||||
Due from related parties | -- | 388 | ||||||||||||||
Derivative asset short-term | -- | 210 | ||||||||||||||
Other current assets | 196 | 613 | 38 | 38 | ||||||||||||
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Total Current Assets | 24,155 | 43,805 | 31,776 | 72,165 | ||||||||||||
Property and Equipment | ||||||||||||||||
Oil and gas properties at cost | 395,129 | 396,588 | 659,792 | 555,280 | ||||||||||||
Less: Accumulated depletion and depreciation | (204,213 | ) | (188,988 | ) | (406,913 | ) | (385,811 | ) | ||||||||
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| 252,879 | 169,469 | |||||||||||||
| 190,916 | 207,600 | |||||||||||||||
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Field and office equipment at cost | 27,919 | 27,403 | 26,955 | 27,246 | ||||||||||||
Less: Accumulated depreciation | (16,824 | ) | (14,702 | ) | (23,715 | ) | (22,728 | ) | ||||||||
|
| 3,240 | 4,518 | |||||||||||||
| 11,095 | 12,701 | |||||||||||||||
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Total Property and Equipment, Net | 202,011 | 220,301 | 256,119 | 173,987 | ||||||||||||
Derivative Contracts Long-Term | — | 13 | ||||||||||||||
Other Assets | 629 | 781 | ||||||||||||||
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Other assets | 673 | 985 | ||||||||||||||
Total Assets | $ | 226,795 | $ | 264,900 | $ | 288,568 | $ | 247,137 | ||||||||
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LIABILITIES AND EQUITY | ||||||||||||||||
Current Liabilities | ||||||||||||||||
Accounts payable | $ | 12,355 | $ | 16,258 | $ | 15,424 | $ | 11,451 | ||||||||
Accrued liabilities | 6,122 | 12,401 | 48,613 | 25,750 | ||||||||||||
Current portion of long-term debt | 3,059 | 2,903 | ||||||||||||||
Due to related parties | 80 | — | ||||||||||||||
Current portion of asset retirement and other long-term obligations | 1,435 | 1,366 | 692 | 2,566 | ||||||||||||
Current portion of deferred tax liability | — | 5,547 | ||||||||||||||
Derivative liability short-term | 7 | 170 | -- | 1,190 | ||||||||||||
Due to related parties | — | 45 | ||||||||||||||
|
| 64,809 | 40,957 | |||||||||||||
Total Current Liabilities | 22,978 | 38,690 | ||||||||||||||
Long-Term Bank Debt | 92,581 | 98,490 | -- | 11,000 | ||||||||||||
Asset Retirement Obligations | 10,452 | 11,269 | 14,707 | 13,525 | ||||||||||||
Deferred Income Taxes | 37,883 | 38,191 | 47,236 | 39,968 | ||||||||||||
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Other Long-Term Obligations | 866 | 1,334 | ||||||||||||||
Total Liabilities | 163,894 | 186,640 | 127,618 | 106,784 | ||||||||||||
Commitments and Contingencies | ||||||||||||||||
Equity | ||||||||||||||||
Common stock, $.10 par value; 2015 and 2014: Authorized: 4,000,000 shares, issued: 3,836,397 shares; outstanding 2015: 2,304,684 shares; 2014: 2,333,404 shares | 383 | 383 | ||||||||||||||
Common stock, $.10 par value; 2023 and 2022: Authorized: 2,810,000 shares, outstanding 2023: 1,820,100 shares; outstanding 2022: 1,901,000 shares. | 281 | 281 | ||||||||||||||
Paid-in capital | 7,854 | 7,186 | 7,555 | 7,555 | ||||||||||||
Retained earnings | 92,878 | 105,662 | 205,669 | 177,566 | ||||||||||||
Accumulated other comprehensive loss, net | (5 | ) | (92 | ) | ||||||||||||
Treasury stock, at cost; 2015: 1,531,713 shares; 2014: 1,502,993 shares | (45,380 | ) | (43,527 | ) | ||||||||||||
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Total Stockholders’ Equity—PrimeEnergy | 55,730 | 69,612 | ||||||||||||||
Non-controlling interest | 7,171 | 8,648 | ||||||||||||||
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Total Equity | 62,901 | 78,260 | ||||||||||||||
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Treasury stock, at cost; 2023: 989,900 shares; 2022: 909,000 | (52,555 | ) | (45,049 | ) | ||||||||||||
Total Stockholders’ Equity | 160,950 | 140,353 | ||||||||||||||
Total Liabilities and Equity | $ | 226,795 | $ | 264,900 | $ | 288,568 | $ | 247,137 | ||||||||
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The accompanying Notes are an integral part of these Consolidated Financial Statements
PRIMEENERGY RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTSTATEMENTS OF OPERATIONSINCOME
(Thousands of dollars, except per share amounts)
| For the Year Ended December 31, | ||||||||
| 2015 | 2014 | |||||||
Revenues | ||||||||
Oil and gas sales | $ | 45,632 | $ | 91,045 | ||||
Realized gain on derivative instruments, net | 21,151 | 135 | ||||||
Field service income | 20,879 | 26,270 | ||||||
Administrative overhead fees | 8,287 | 9,373 | ||||||
Unrealized (loss) gain on derivative instruments | (16,901 | ) | 17,574 | |||||
Other income | 58 | 183 | ||||||
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Total Revenues | 79,106 | 144,580 | ||||||
Costs and Expenses | ||||||||
Lease operating expense | 35,206 | 43,972 | ||||||
Field service expense | 17,641 | 21,185 | ||||||
Depreciation, depletion, amortization and accretion on discounted liabilities | 31,551 | 25,864 | ||||||
Gain on settlement of asset retirement obligations | — | (1,797 | ) | |||||
General and administrative expense | 12,267 | 14,460 | ||||||
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Total Costs and Expenses | 96,665 | 103,684 | ||||||
Gain on Sale and Exchange of Assets | 1,386 | 6,115 | ||||||
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(Loss) income from Operations | (16,173 | ) | 47,011 | |||||
Other Income and Expenses | ||||||||
Less: Interest expense | 3,627 | 4,018 | ||||||
Add: Interest income | 2 | — | ||||||
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| |||||
(Loss) income Before (Benefit) Provision for Income Taxes | (19,798 | ) | 42,993 | |||||
(Benefit) provision for Income Taxes | (6,648 | ) | 13,844 | |||||
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Net (Loss) income | (13,150 | ) | 29,149 | |||||
Less: Net (Loss) income Attributable to Non-Controlling Interest | (366 | ) | 2,103 | |||||
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Net (Loss) income Attributable to PrimeEnergy | $ | (12,784 | ) | $ | 27,046 | |||
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Basic (Loss) income Per Common Share | $ | (5.53 | ) | $ | 11.45 | |||
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Diluted (Loss) income Per Common Share | $ | (5.53 | ) | $ | 8.68 | |||
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For the Years Ended | ||||||||
2023 | 2022 | |||||||
Revenues and other income: | ||||||||
Oil | $ | 87,906 | $ | 90,803 | ||||
Natural gas | 7,935 | 18,428 | ||||||
Natural gas liquids | 11,901 | 14,887 | ||||||
Field service | 15,383 | 12,978 | ||||||
Interest and other income, net | 417 |
| 267 |
| ||||
Gain (loss) on derivative instruments, net | 414 | (12,039 | ) | |||||
Gain on disposition of assets, net | 8,854 | 31,789 | ||||||
| 132,810 | 157,113 | ||||||
Costs and expenses: | ||||||||
Oil and gas production | 31,892 | 30,702 | ||||||
Production and advalorem taxes | 7,112 | 7,114 | ||||||
Field service | 11,744 | 11,094 | ||||||
Depreciation, depletion and amortization | 30,976 | 27,401 | ||||||
Accretion of discount on asset retirement obligations | 684 | 667 | ||||||
General and administrative | 15,645 | 20,233 | ||||||
| Interest | 535 | 909 | ||||||
| 98,588 | 98,120 | ||||||
Income before income taxes | 34,222 | 58,993 | ||||||
Income tax provision | 6,119 | 10,329 | ||||||
Net income attributable to common stockholders | $ | 28,103 | $ | 48,664 | ||||
| Net Income per share attributable to Common Stockholders: | ||||||||
| Basic | $ | 15.19 | $ | 24.91 | ||||
| Diluted | $ | 10.77 | $ | 17.95 | ||||
| Weighted average shares Outstanding: | ||||||||
| Basic | 1,849,780 | 1,953,916 | ||||||
| Diluted | 2,608,786 | 2,711,170 | ||||||
The accompanying Notes are an integral part of these Consolidated Financial Statements
PRIMEENERGY RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTSTATEMENTS OF COMPREHENSIVE INCOMEEQUITY
(Thousands of dollars)dollars, except share amounts)
| For the Year Ended December 31, | ||||||||
| 2015 | 2014 | |||||||
Net (Loss) income | $ | (13,150 | ) | $ | 29,149 | |||
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Other Comprehensive Income, net of taxes: | ||||||||
Changes in fair value of hedge positions, net of taxes of $(50) and $(17), respectively | 87 | 31 | ||||||
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Total other comprehensive income | 87 | 31 | ||||||
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Comprehensive (loss) income | (13,063 | ) | 29,180 | |||||
Less: Comprehensive (loss) income attributable to non-controlling interest | (366 | ) | 2,103 | |||||
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Comprehensive (loss) income attributable to PrimeEnergy | $ | (12,697 | ) | $ | 27,077 | |||
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Common Stock | Additional |
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Shares | Common | Paid-In Capital | Retained Earnings | Treasury Stock | Total Equity | |||||||||||||||||||
Balance at December 31, 2021 | 1,992,077 | $ | 281 | $ | 7,555 | $ | 128,902 | $ | (37,647 | ) | $ | 99,091 | ||||||||||||
Purchase of treasury stock | (91,077 | ) | — | — | — | (7,402 | ) | (7,402 | ) | |||||||||||||||
Net income | — | — | — | 48,664 | — | 48,664 | ||||||||||||||||||
Balance at December 31, 2022 | 1,901,000 | $ | 281 | $ | 7,555 | $ | 177,566 | $ | (45,049 | ) | $ | 140,353 | ||||||||||||
Purchase of treasury stock | (80,900 | ) | — | — | — | (7,506 | ) | (7,506 | ) | |||||||||||||||
Net income | — | — | — | 28,103 | — | 28,103 | ||||||||||||||||||
Balance at December 31, 2023 | 1,820,100 | $ | 281 | $ | 7,555 | $ | 205,669 | $ | (52,555 | ) | $ | 160,950 | ||||||||||||
The accompanying Notes are an integral part of these Consolidated Financial Statements
PRIMEENERGY RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTSTATEMENTS OF EQUITYCASH FLOWS
(Thousands of dollars)
| Common Stock | Additional Paid-In Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Treasury Stock | Total Stockholders’ Equity – PrimeEnergy | Non- Controlling Interest | Total Equity | |||||||||||||||||||||||||||||
| Shares | Amount | |||||||||||||||||||||||||||||||||||
Balance at December 31, 2013 | 3,836,397 | $ | 383 | $ | 6,803 | $ | 78,616 | $ | (123 | ) | $ | (40,251 | ) | $ | 45,428 | $ | 7,710 | $ | 53,138 | |||||||||||||||||
Purchase 55,380 shares of common stock | — | — | — | — | — | (3,276 | ) | (3,276 | ) | — | (3,276 | ) | ||||||||||||||||||||||||
Net income | — | — | — | 27,046 | — | — | 27,046 | 2,103 | 29,149 | |||||||||||||||||||||||||||
Other comprehensive income, net of taxes | — | — | — | — | 31 | — | 31 | — | 31 | |||||||||||||||||||||||||||
Purchase of non-controlling interest | — | — | 383 | — | — | — | 383 | (657 | ) | (274 | ) | |||||||||||||||||||||||||
Distributions to non-controlling interest | — | — | — | — | — | — | — | (508 | ) | (508 | ) | |||||||||||||||||||||||||
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Balance at December 31, 2014 | 3,836,397 | $ | 383 | $ | 7,186 | $ | 105,662 | $ | (92 | ) | $ | (43,527 | ) | $ | 69,612 | $ | 8,648 | $ | 78,260 | |||||||||||||||||
Purchase 28,720 shares of common stock | — | — | — | — | — | (1,853 | ) | (1,853 | ) | — | (1,853 | ) | ||||||||||||||||||||||||
Net income | — | — | — | (12,784 | ) | — | — | (12,784 | ) | (366 | ) | (13,150 | ) | |||||||||||||||||||||||
Other comprehensive income, net of taxes | — | — | — | — | 87 | — | 87 | — | 87 | |||||||||||||||||||||||||||
Purchase of non-controlling interest | — | — | 668 | — | — | — | 668 | (1,077 | ) | (409 | ) | |||||||||||||||||||||||||
Distributions to non-controlling interest | — | — | — | — | — | — | — | (34 | ) | (34 | ) | |||||||||||||||||||||||||
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Balance at December 31, 2015 | 3,836,397 | $ | 383 | $ | 7,854 | $ | 92,878 | $ | (5 | ) | $ | (45,380 | ) | $ | 55,730 | $ | 7,171 | $ | 62,901 | |||||||||||||||||
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For the Years Ended | ||||||||
2023 | 2022 | |||||||
Cash Flows from Operating Activities: | ||||||||
Net Income | $ | 28,103 | $ | 48,664 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||
Depreciation, depletion and amortization | 30,976 | 27,401 | ||||||
Accretion of discount on asset retirement obligations | 684 | 667 | ||||||
Gain on sale and exchange of assets | (8,854 | ) | (31,789 | ) | ||||
Unrealized gain on derivative instruments | -- |
| (4,605 | ) | ||||
| Non cash realized gain on derivative instruments, net | (980 | ) | -- | |||||
Provision for deferred income taxes | 7,268 | 1,225 | ||||||
Changes in assets and liabilities: | ||||||||
Accounts receivable | (8,492 | ) | 2,096 | |||||
Allowance for doubtful accounts | 338 | (35 | ) | |||||
Due from related parties | 388 | (388 | ) | |||||
Due to related parties | 80 | (52 | ) | |||||
Prepaid obligations | 32,463 | (32,106 | ) | |||||
Other current assets | -- | 2 | ||||||
Accounts payable | 3,973 | 4,169 | ||||||
Accrued liabilities | 22,863 | 17,929 | ||||||
Other assets | 673 | 100 | ||||||
Other long-term liabilities | (468 | ) | (151 | ) | ||||
Net Cash Provided by Operating Activities | 109,015 | 33,127 | ||||||
Cash Flows from Investing Activities: | ||||||||
Capital expenditures, including exploration expense | (113,779 | ) | (15,974 | ) | ||||
Proceeds from sale of properties and equipment | 8,082 | 31,445 | ||||||
Net Cash (Used in) Provided by Investing Activities | (105,697 | ) | 15,471 | |||||
Cash Flows from Financing Activities: | ||||||||
Purchase of stock for treasury | (7,506 | ) | (7,402 | ) | ||||
Increase in long-term bank debt and other long-term obligations | -- | 11,000 | ||||||
Repayment of long-term bank debt and other long-term obligations | (11,294 | ) | (36,000 | ) | ||||
Net Cash Used in Financing Activities | (18,800 | ) | (32,402 | ) | ||||
Net (Decrease) Increase in Cash and Cash Equivalents | (15,482 | ) | 16,196 | |||||
Cash and Cash Equivalents at the Beginning of the Year | 26,543 | 10,347 | ||||||
Cash and Cash Equivalents at the End of the Year | $ | 11,061 | $ | 26,543 | ||||
Supplemental Disclosures: | ||||||||
Income taxes paid during the year | $ | 9,009 | $ | 539 | ||||
Interest paid during the year | $ | 569 | $ | 842 | ||||
The accompanying Notes are an integral part of these Consolidated Financial Statements
PRIMEENERGY RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of dollars)
| For the Year Ended December 31, | ||||||||
| 2015 | 2014 | |||||||
Cash Flows from Operating Activities: | ||||||||
Net (loss) income | $ | (13,150 | ) | $ | 29,149 | |||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||
Depreciation, depletion, amortization and accretion on discounted liabilities | 31,551 | 25,864 | ||||||
Gain on sale of properties | (1,386 | ) | (6,115 | ) | ||||
Unrealized gain (loss) on derivative instruments | 16,856 | (17,574 | ) | |||||
Provision for deferred income taxes | (6,389 | ) | 13,237 | |||||
Gain on settlement of asset retirement obligations | — | (1,797 | ) | |||||
Changes in assets and liabilities: | ||||||||
Decrease in accounts receivable | 2,769 | 5,379 | ||||||
Decrease (increase) in due from related parties | 308 | (247 | ) | |||||
Decrease in inventories | 64 | 24 | ||||||
Decrease in prepaid expenses and other assets | 410 | 286 | ||||||
(Decrease) increase in accounts payable | (3,539 | ) | 534 | |||||
(Decrease) increase in accrued liabilities | (6,280 | ) | 7,425 | |||||
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Net Cash Provided by Operating Activities | 21,214 | 56,165 | ||||||
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Cash Flows from Investing Activities: | ||||||||
Capital expenditures, including exploration expense | (14,550 | ) | (38,758 | ) | ||||
Proceeds from sale of properties and equipment | 1,926 | 6,834 | ||||||
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Net Cash Used in Investing Activities | (12,624 | ) | (31,924 | ) | ||||
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Cash Flows from Financing Activities: | ||||||||
Purchase of stock for treasury | (1,853 | ) | (3,276 | ) | ||||
Purchase of non-controlling interests | (409 | ) | (274 | ) | ||||
Increase in long-term bank debt and other long-term obligations | 27,700 | 57,417 | ||||||
Repayment of long-term bank debt and other long-term obligations | (33,453 | ) | (77,917 | ) | ||||
Distribution to non-controlling interest | (34 | ) | (508 | ) | ||||
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Net Cash Used in Financing Activities | (8,049 | ) | (24,558 | ) | ||||
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Net Increase (Decrease) in Cash and Cash Equivalents | 541 | (317 | ) | |||||
Cash and Cash Equivalents at the Beginning of the Year | 9,209 | 9,526 | ||||||
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Cash and Cash Equivalents at the End of the Year | $ | 9,750 | $ | 9,209 | ||||
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Supplemental Disclosures: | ||||||||
Income taxes paid during the year | $ | 410 | $ | 320 | ||||
Interest paid during the year | $ | 3,695 | $ | 4,025 | ||||
The accompanying Notes are an integral part of these Consolidated Financial Statements
PRIMEENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Description of Operations and Significant Accounting Policies
Nature of Operations:
PrimeEnergy Resources Corporation (“PEC”PERC”), a Delaware corporation, was organized in March 1973 and is engaged in the development, acquisition and production of oil and natural gas properties. PrimeEnergy Resources Corporation and its subsidiaries are herein referred to as the “Company.” The Company owns leasehold, mineral and royalty interests in producing and non-producing oil and gas properties across the United States, including Colorado, Kansas, Louisiana, Mississippi, Montana, New Mexico, North Dakota,primarily in Oklahoma, Texas, West Virginia and Wyoming and the Gulf of Mexico.Texas. The Company operates over 1,500approximately 534 active wells and owns non-operating interests and royalties in approximately 400952 additional wells. Additionally, the Company provides well-servicing support operations, site-preparation and construction services for oil and gas drilling and reworking operations, both in connection with the Company’s activities and providing contract services for third parties. The Company is publicly traded on the NASDAQNasdaq stock market under the symbol “PNRG.” PECPERC owns Eastern Oil Well Service Company (“EOWSC”), and EOWS Midland Company (“EMID”) and Southwest Oilfield Construction Company (“SOCC”), all of which perform oil and gas field servicing. PECPERC also owns Prime Operating Company (“POC”), which serves as operator for most of the producing oil and gas properties owned by the Company and affiliated entities. PEC also owns Prime Offshore L.L.C. (“Prime Offshore”), formerly F-W Oil Exploration LLC, which has owned and operated properties in the Gulf of Mexico. PrimeEnergy Management Corporation (“PEMC”), a wholly-owned subsidiary, acts as the managing general partner, providing administration, accounting and tax preparation services for 18 limited partnerships and 2 trusts (collectively, the “Partnerships”).Company. The markets for the Company’s products are highly competitive, as oil and gas are commodity products and prices depend upon numerous factors beyond the control of the Company, such as economic, political and regulatory developments and competition from alternative energy sources.
Consolidation and Presentation:Presentation
The consolidated financial statements include the accounts of PrimeEnergy Resources Corporation, and its subsidiaries and the Partnerships, using the full consolidation method for those partnerships which are controlled by the Company. The proportionate consolidation method is used to account for those undivided interests in oil and gas properties owned by the Company as well as interests held in unincorporated legal entities, such as partnerships, engaged in oil and gas production, which are not controlled by the Company. For those entities which are proportionately consolidated, the proportionate share of each entity’s assets, liabilities, revenue and expenses is included in the appropriate classifications in the consolidated financial statements. Reserve estimates associated with the proportionately consolidated oil and gas interests are calculated for each property at the Partnership level, and depletion, depreciation and amortization (“DD&A”) rates are determined at the Partnership level. The Company’s reserve estimates are based on the ownership percentage of Partnership reserve reports. DD&A expense and evaluation of impairment may differ from the Partnership as the Company’s cost basis for the Partnership interests acquired may be different than the cost basis at the Partnership level for properties acquired by the Partnership.subsidiaries. All significant intercompany balances and transactions are eliminated in preparing the consolidated financial statements.
Reclassifications:
Certain reclassifications have been made to prior year statements to conform with the current year presentation. These reclassifications have no impact on net income and no material impact on any other financial statement captions.
Subsequent Events:
Subsequent events have been evaluated through the date that the consolidated financial statements were issued. During this period, there were no material subsequent items requiring disclosure.disclosure, other than as stated in Footnote 4 and Footnote 5, to these consolidated financial statements.
Use of Estimates:
The preparation of consolidated financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Estimates of oil and gas reserves, as determined by independent petroleum engineers, are continually subject to revision based on price, production history and other factors. Depletion expense, which is computed based on the units of production method, could be significantly impacted by changes in such estimates. Additionally, U.S. generally accepted accounting principles require that if the expected future undiscounted cash flows from an asset isare less than its carrying cost, that asset must be written down to its fair market value. As the fair market value of an oil and gas property will usually be significantly less than the total undiscounted future net revenues expected from that asset, slight changes in the estimates used to determine future net revenues from an asset could lead to the necessity of recording a significant impairment of that asset.
PropertyCash and Equipment:cash equivalents:
The Company's cash and cash equivalents include cash on hand and short-term investments, such as money market deposits or similar type instruments, with a maturity of three months or less when purchased.
Accounts receivable, net:
The Company's net accounts receivable balance is primarily comprised of oil and gas sales receivables, joint interest receivables and other receivables for which the Company does not require collateral security. The Company's share of oil and gas production is sold to various purchasers and under various joint operating agreements. The Company records allowances for doubtful accounts based on historical collection experience, current and future economic and market conditions, the length of time that the accounts receivables have been outstanding and the financial condition of its purchasers. The Company's credit risk related to collecting accounts receivables is mitigated by using credit and other financial criteria to evaluate the credit standing of the entity obligated to make payment on the accounts receivable, and where appropriate, the Company obtains assurances of payment, such as a guarantee by the parent company of the counterparty, letters of credit or other credit support.
The Company followsconsiders forward-looking information to estimate expected credit losses. The Company establishes allowances for bad debts equal to the “successful efforts”estimable portions of accounts receivable for which failure to collect is expected to occur. The Company estimates uncollectible amounts for joint interest receivables based on the length of time that the accounts receivables have been outstanding, historical collection experience and current and future economic and market conditions. Allowances for doubtful accounts are recorded as reductions to the carrying values of the receivables included in the Company's consolidated balance sheets and are recorded in expense in the consolidated statements of operations in the accounting periods during which failure to collect an estimable portion is determined to be probable. The Company's allowance for doubtful accounts totaled $674 thousand and $336 thousand as of December 31, 2023 and 2022, respectively.
In June 2016, the FASB issued ASU 2016-13, Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. The standard’s main goal is to improve financial reporting by requiring earlier recognition of credit losses on financing receivables and other financial assets in scope. This guidance is effective for Smaller Reporting Companies for fiscal years beginning after December 15, 2022, including interim periods within those fiscal periods. The Company adopted this standard effective January 1, 2023. The adoption and implementation of this ASU did not have a material impact on the Company’s financial statements.
Oil and gas properties:
The Company utilizes the successful efforts method of accounting for its oil and gas properties. Under the successful effortsthis method, all costs of acquiring undevelopedassociated with productive wells and nonproductive development wells are capitalized while nonproductive exploration costs and geological and geophysical expenditures are expensed. Oil and gas leasehold acquisition costs are capitalized when incurred and included as unproved oil and gas leasehold acreage, including lease bonuses, brokers’ feesproperties in the consolidated balance sheets. The Company does not carry the costs of drilling an exploratory well as an asset in its consolidated balance sheets following the completion of drilling unless both of the following conditions are met: (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well and other(ii) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. The Company’s exploratory wells include extension wells that extend the limits of a known reservoir. Due to the capital intensive nature and the geographical location of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination on its commercial viability. In these instances, the project’s feasibility is not contingent upon price improvements or advances in technology, but rather the Company’s ongoing efforts and expenditures related costs are capitalized. Provisions for impairment of undeveloped oil and gas leases areto accurately predicting the hydrocarbon recoverability based on periodic evaluations. Annual lease rentalswell information, gaining access to other companies’ production data in the area, transportation or processing facilities, and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and being pursued constantly. Consequently, the Company’s assessment of suspended exploratory/extension well costs is continuous until a decision can be made that the project has found sufficient proved reserves to sanction the project or is determined to be noncommercial and is charged to exploration expenses, including geological and geophysical expenses and exploratory dry holeabandonments expense. As of December 31, 2023, the Company had no such suspended well costs.
The capitalized costs are charged against income as incurred. Costs of drilling and equipping productive wells, including development dry holes and related production facilities, are capitalized. All other property and equipment are carried at cost. Depreciation and depletion of oil and gas production equipment andproved properties are determined underdepleted using the unit-of-production method based on estimated proved developed recoverable oilreserves. Costs of significant nonproducing properties, wells in the process of being drilled and gas reserves.in-process development projects are excluded from depletion until the related project is completed and proved reserves are established or, if unsuccessful, abandonments expense is recognized. Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depletion, depreciation and amortization, if doing so does not materially impact the depletion rate of its amortization base. Generally, no gain or loss is recorded until an entire amortization base is sold. However, gain or loss is recorded from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base.
Field and Office Equipment:
Field and office equipment is carried at cost. Depreciation of all other equipment is determined under the straight-line method using various rates based on useful lives generally ranging from 5 to 10 years. The cost of assets and related accumulated depreciation is removed from the accounts when such assets are disposed of, and any related gains or losses are reflected in current earnings.
Leases:
The Company enters into operating leases for its office space in Houston and Midland, Texas. The Company recognizes lease expense on a straight-line basis over the lease term. Lease right-of-use assets and liabilities are initially recorded on the lease commencement date based on the present value of lease payments over the lease term. As the Company's lease contracts do not provide an implicit discount rate, the Company uses its incremental borrowing rate, which is determined based on information available at the commencement date of a lease. Leases may include renewal, purchase or termination options that can extend or shorten the term of the lease. The exercise of those options is at the Company's sole discretion and is evaluated at inception and throughout the contract to determine if a modification of the lease term is required. Leases with an initial term of 12 months or less are not recorded as a lease right-of-use asset and liability. See Note 5 for additional information.
Capitalization of Interest:
Interest costs related to financing major oil and gas projects in progress are capitalized until the projects are evaluated or until the projects are substantially complete and ready for their intended use if the projects are evaluated and successful.
Impairment of Long-Lived Assets:
The Company reviews long-lived assets, including oil and gas properties, for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. If the carrying amounts are not expected to be recovered by undiscounted cash flows, the assets are impaired, and an impairment loss is recorded. The amount of impairment is based on the estimated fair value of the assets determined by discounting anticipated future net cash flows.
Fair Value:
The Company follows the authoritative guidance that establishes a formal framework for measuring fair values of assets and liabilities in financial statements that are already required by U.S. generally accepted accounting principles to be measured at fair value. The guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The transaction is based on a hypothetical transaction in the principal or most advantageous market considered from the perspective of the market participant that holds the asset or owes the liability.
The Company utilizes market data or assumptions that market participants who are independent, knowledgeable and willing and able to transact would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Company attempts to utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Company is able to classify fair value balances based on the observability of those inputs. The guidance establishes a formal fair value hierarchy based on the inputs used to measure fair value. The hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority.
Revenue recognition:
The majority of the Company’s production is operated by third party operators where we elect to market our products under the joint operating agreements. Accordingly, we receive our proportionate share of revenue proceeds for production sold by the operator under the operator’s marketing agreements. The Company recognizes revenue and any costs indicated by the operator in the related production period.
The Company recognizes revenue related to production from properties operated by the Company when control of the promised goods or services is transferred to customers at an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services.
Oil sales. The Company recognizes oil sales revenue when (i) control/custody transfers to the purchaser and (ii) the agreed-upon index price, net of any price differentials, is fixed and determinable. Any costs incurred prior to the transfer of control to the customer, such as gathering and transportation costs, are recognized as oil and gas production costs.
NGL and gas sales. Under the majority of the Company’s gas processing contracts, gas is delivered to a midstream processing entity and the Company recognizes revenue when the products are delivered to the midstream gathering or processing entity at a specified index price, net of downstream gathering and processing fees.
Field service income. The majority of the Company’s services are performed under Master Service Agreements. The Company recognizes revenue when the products and services are provided to the customer.
Asset Retirement Obligation:
The Company follows the accounting standard for asset retirement obligation.
The asset retirement obligation primarily represents the estimated present value of the amount the Company will incur to plug, abandon and remediate producing properties (including removal of offshore platforms) at the end of their productive lives, in accordance with applicable state laws. The Company determined its asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The asset retirement obligation is recorded as a liability at its estimated present value at its inception, with an offsetting increase to producing properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the statementstatements of operations.
Income Taxes:
The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to turn around. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized. As of December 31, 20152023 and 2014, we2022, the Company had no valuation allowance.
The Company is required to make judgments, including estimating reserves for potential adverse outcomes regarding tax positions that the Company has taken. The Company accounts for uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The effective tax rate and the tax basis of assets and liabilities reflect management’s estimates of the ultimate outcome of various tax uncertainties.
General and Administrative Expenses:
General and administrative expenses represent cost and expenses associated with the operation of the Company.
Earnings Per Common Share:
Basic earnings per share are computed by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share reflect per share amounts that would have resulted if dilutive potential common stock had been converted to common stock in gain periods.
Statements of Cash Flows:
For purposes of the consolidated statements of cash flows, the Company considers short-term, highly liquid investments with original maturities of less than ninety days to be cash equivalents.
Concentration of Credit Risk:
The Company maintains significant banking relationships with financial institutions in the State of Texas. The Company limits its risk by periodically evaluating the relative credit standing of these financial institutions. The Company’s oil and gas production purchasers consist primarily of independent marketers and major gas pipeline companies.
Hedging:
The Company periodically enters into oil and gas financial instruments to manage its exposure to oil and gas price volatility. The oil and gas reference prices upon which the price hedging instruments are based reflect various market indices that have a high degree of historical correlation with actual prices received by the Company.
The financial instruments are accounted for in accordance with applicable accounting standards for derivative instruments and hedging activities. Such standards require that applicable derivative instruments be measured at fair market value and recognized as assets or liabilities in the balance sheet. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation is generally established at the inception of a derivative. For derivatives designated as cash flow hedges and meeting applicable effectiveness guidelines, changes in fair value, to the extent effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. At December 31, 2015 and 2014, the entire other comprehensive income amount comprised of the impact of cash flow hedges. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value of a derivative resulting from ineffectiveness or an excluded component of the gain/loss is recognized immediately in the statementstatements of operations.income.
Recently Issued Accounting Standards:New accounting standards
The. In November 2023, the FASB issued ASU 2014-09,Revenue from Contracts with CustomersAccounting Standards Update 2023-07, "Segment Reporting (Topic 606). This ASU supersedes theRevenue recognition requirements in Topic 605, Revenue Recognition and industry-specific guidance in Subtopic 932-605. Extractivies – Oil and Gas Revenue Recognition.This ASU provides guidance concerning the recognition and measurement of revenue from contracts with customers. Its objective is280): Improvements to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. The effective date for ASU 2014-09 was delayed through the issuance of ASU 2015-14, Revenue from Contracts with Customers – Deferral or theEffective Date,to annual and interim periods beginning in 2018 and is required to be adopted using either the retrospective or cumulative effect (modified retrospective) transition method, with early adoption permitted in 2017. The Company is evaluating the impact this ASU will have on its consolidated financial statements and related disclosures and does not plan on early adopting.
The FASB issued ASU 2015-02,Consolidation (Topic 810): Amendments to the Consolidation Analysis.This ASU provides additional guidance to reporting entities in evaluating whether certain legal entities such, as limited partnerships, limited liability corporations and securitization structures, should be consolidated. The ASU is considered to be an improvement on current accounting requirements as it reduces the number of existing consolidation models. This ASU is effective for the Company beginning January 1, 2016 and will be applied using the retrospective approach. This ASU will not have a material impact on the Company’s consolidated financial statements and related disclosures.
The FASB issued ASU 2015-03,Interest – Imputation of Interest (Topic 835): Simplifying the Presentation of Debt Issuance Costsand ASU 2015-15,Interest – Imputation of Interest (Topic 835): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements.These ASU’s require debt issuance costs related to a recognized debt liability, except for those related to revolving credit facilities, to be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability rather than an asset. These ASU’sare effective for the Company beginning January 1, 2016 and will be applied using the retrospective approach. These ASU’s will not have a material impact on the Company’s consolidated financial statements and related disclosures.
The FASB issued ASU 2015-17,Balance Sheet Classification of Deferred Taxes.This ASU requires that all deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. This ASU is effective for annual and interim periods beginning in 2017 and can be applied prospectively or retrospectively, with early adoption permitted. This ASU will be early-adopted by the Company effective January 1, 2016 and will be applied using the retrospective approach. This ASU will not have a material impact on the Company’s financial statements and related disclosures.
The FASB issued ASU 2016-02,Leases (Topic 842).This ASU requires lessee recognition on the balance sheet of a right-of-use asset and a lease liability, initially measured at the present value of the lease payments. It further requires recognition in the income statement of a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a generally straight-line basis. Finally, it requires classification of all cash payments within operating activities in the statement of cash flows. ItReportable Segment Disclosures," which is effective for fiscal years commencingbeginning after December 15, 20182023 and interim periods within fiscal years beginning after December 15, 2024 with early adoption permitted. The amendments in this Accounting Standards Update are focused on reportable segment disclosure requirements, primarily related to significant segment expenses, and are required to be applied retrospectively to all prior periods presented in a company's consolidated financial statements.
In December 2023, the FASB issued Accounting Standards Update 2023-09, "Income Taxes (Topic 740): Improvements to Income Tax Disclosures," which is effective for fiscal years beginning after December 15, 2024 with early adoption permitted. This ASU will not haveThe amendments in this Accounting Standards Update are focused on income tax disclosure requirements, primarily related to the income tax rate reconciliation and income taxes paid, with prospective application to a material impact on the Company’scompany's consolidated financial statements and relatedrecommended.
The Company is currently assessing the impacts of these new accounting standards on its disclosures.
2. Acquisitions and Dispositions
Historically,
2023 Transactions:
In the first quarter of 2023, the Company has repurchasedsold 7.8 surface acres in Midland County, Texas receiving gross proceeds of $436,050 and recognizing a gain of $47,000.
In the non-controlling interestssecond quarter of 2023, the Company acquired 55 net acres in the South Stiles area of Reagan County, Texas for $605,000, and in a separate agreement also in Reagan County, the Company sold 320 non-core acres for proceeds of $6,000,000. In addition, the Company sold 36.51% interest in one well in Midland County, Texas for proceeds of $60,000.
In the third quarter of 2023, the Company sold a non-core 38.25-acre leasehold tract in Martin County, Texas for proceeds of $899,000 and sold 3 surface acres in Liberty County, Texas for net proceeds of $37,053. Also in the third quarter, in various counties of Oklahoma, the Company divested its interest in 39 wells, reducing its future plugging liability by approximately $1.5 million. Effective July 1, 2023, the Company acquired the operations of 36 wells from DE Permian and 50% of DE Permian’s original ownership in such wells. In addition, in Reagan County, Texas, the Company acquired 114.52 net acres from DE Permian for $1,700,853 and assigned to them 203.23 net acres.
In the fourth quarter of 2023, the Company sold 136 surface acres in Oklahoma for net proceeds of $306,000 and in Midland Texas sold 9.35 net acres for proceeds of $280,423.
2022 Transactions:
In the first quarter of 2022, the Company sold 1,809 net leasehold acres in Reagan and Midland Counties, Texas through two separate transactions receiving gross proceeds of $14.0 million. In the second quarter of 2022, the Company sold 241 net acres in Canadian County, Oklahoma for $845,000. In the third quarter of 2022, the Company sold an additional 113 net acres in Canadian County, Oklahoma for $423,700.
On November 14, 2022, the Company completed an acreage exchange of approximately 725 net acres in the Midland Basin creating a block of 1,200 contiguous acres. The Company entered into an agreement, including this acreage, to create a 2,560-acre AMI for the joint development of horizontal wells. As part of the partners and trust unit holdersagreement, the Company sold a portion of its interest in certainthis acreage to the joint development partner for proceeds of the Partnerships, which consist primarily of oil and gas interests. The Company purchased such non-controlling interests in an amount totaling $409,000 in 2015 and $274,000 in 2014.$16.1 million.
3. Additional Balance Sheet Information
Accounts receivable, net at December 31, 20152023 and 20142022 consisted of the following:
| December 31, | December 31, | |||||||||||||||
(Thousands of dollars) | 2015 | 2014 | 2023 | 2022 | ||||||||||||
Joint interest billings | $ | 2,667 | $ | 2,882 | $ | 2,560 | $ | 1,806 | ||||||||
Trade receivables | 1,452 | 1,980 | 2,345 | 1,762 | ||||||||||||
Oil and gas sales | 3,576 | 6,245 | 14,457 | 8,894 | ||||||||||||
Taxes | 1,458 | -- | ||||||||||||||
Other | 2,377 | 1,751 | 155 | 21 | ||||||||||||
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| 20,975 | 12,483 | |||||||||||||
| 10,072 | 12,858 | |||||||||||||||
Less: Allowance for doubtful accounts | (529 | ) | (543 | ) | ||||||||||||
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| |||||||||||||||
Less: Allowance for credit losses | (674 | ) | (336 | ) | ||||||||||||
Total | $ | 9,543 | $ | 12,315 | $ | 20,301 | $ | 12,147 | ||||||||
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Accounts payable at December 31, 20152023 and 20142022 consisted of the following:
| December 31, | December 31, | |||||||||||||||
(Thousands of dollars) | 2015 | 2014 | 2024 | 2022 | ||||||||||||
Trade | $ | 3,289 | $ | 3,995 | $ | 9,847 | $ | 5,142 | ||||||||
Royalty and other owners | 5,973 | 8,444 | 4,405 | 3,600 | ||||||||||||
Partner advances | 1,083 | 1,344 | 946 | 1,111 | ||||||||||||
Prepaid drilling deposits | 390 | 786 | ||||||||||||||
Other | 1,620 | 1,689 | 226 | 1,598 | ||||||||||||
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Total | $ | 12,355 | $ | 16,258 | $ | 15,424 | $ | 11,451 | ||||||||
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Accrued liabilities at December 31, 20152023 and 20142022 consisted of the following:
| December 31, | December 31, | |||||||||||||||
(Thousands of dollars) | 2015 | 2014 | 2023 | 2022 | ||||||||||||
Compensation and related expenses | $ | 2,294 | $ | 2,350 | $ | 10,324 | $ | 9,743 | ||||||||
Property costs | 3,302 | 9,204 | 33,264 | 6,413 | ||||||||||||
Income tax | — | 554 | ||||||||||||||
Taxes | 929 | 9,352 | ||||||||||||||
Lease operating costs | 3,898 | 1,695 | ||||||||||||||
Other | 526 | 293 | 198 | 242 | ||||||||||||
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Total | $ | 6,122 | $ | 12,401 | $ | 48,613 | $ | 25,750 | ||||||||
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4. Property and Equipment
Capitalized interest is included as part of the cost of oil and gas properties. The capitalized rates are based upon the Company’s weighted-average cost of borrowings used to finance the expenditures. There was no interest capitalized during 2015 or 2014.
5. Long-Term Debt
Bank Debt:
Effective
On July 30, 2010,5, 2022, the Company and its lenders entered into a SecondFourth Amended and Restated Credit Agreement between Compass Bank as agent and a syndicated group of lenders (“(the “2022 Credit Agreement”). The with a maturity date of June 1, 2026. Under the 2022 Credit Agreement, the Company has a revolving line of credit and letter of credit facility of up to $250$300 million subject to a borrowing base that is determined semi-annually by the lenders based upon the Company’s consolidated financial statements and the estimated value of the Company’s oil and gas properties, in accordance with a final maturity datethe Lenders’ customary practices for oil and gas loans. The initial borrowing base of July 30, 2017.the agreement is $75 million. The credit facility is secured by substantially all of the Company’s oil and gas properties. The credit facility is subject to a borrowing base determined by the lenders taking into consideration the estimated value of PEC’s oil and gas properties in accordance with the lenders’ customary practices for oil and gas loans. This process involves reviewing PEC’s estimated proved reserves and their valuation. The borrowing base is re-determined semi-annually, and the available borrowing amount could be increased or decreased as a result of such re-determination. In addition, PEC and the lenders each have at their discretion the right to request the borrowing base be re-determined with a maximum of one such request each year. A revision to PEC’s reserves may prompt such a request on the part of the lenders, which could possibly result in a reduction in the borrowing base and availability under the credit facility. At any time if the sum of the outstanding borrowings and letter of credit exposures exceed the applicable portion of the borrowing base, PEC would be required to repay the excess amount within a prescribed period.
The Credit Agreement has been amended from time to time to further define the limitations on loans or advances and investments made in the Company’s limited partnerships; modify the Company’s borrowing base and monthly reduction amounts; remove the floor rate component of LIBO rate loans; modify financial reporting requirements to the agent; increase hedging allowances; allow for a one-time advance to be made to the Company’s offshore subsidiary; and amend restrictions on the payments for dividends, distributions or repurchase of PEC’s stock.
The2022 Credit Agreement includes terms and covenants that require the Company to maintain a minimum current ratio and total indebtedness to EBITDAX (earnings before depreciation, depletion, amortization, taxes, interest expense and exploration costs) ratio and interest coverage ratio, as defined, and restrictions are placed on the payment of dividends, the amount of treasury stock the Company may purchase, and commodity hedge agreements, and loans and investments in its consolidated subsidiaries and limited partnerships.agreements.
Under the Credit Agreement, the maximum percentage of production available to enter into commodity hedge agreements is 90% of proved developed producing reserves for each of the next succeeding four calendar years for crude oil and natural gas computed separately. In addition, the Company’s restrictions on the payment of dividends, distributions or purchase of treasury stock is limited to an aggregate of $5.0 million in each calendar year.
AtOn December 31, 2015, the credit facility borrowing base was $95.0 million with no monthly reduction amount. The borrowings made within the credit facility may be placed in a base rate loan or LIBO rate loan. The Company’s borrowing rates in the credit facility provide for base rate loans at the prime rate (3.50% at December 31, 2015) plus applicable margin utilization rates that range from 1.75% to 2.50%, and LIBO rate loans at LIBO published rates plus applicable utilization rates that range from 2.75% to 3.00%. At December 31, 2015,2022, the Company had in place one base rate loan and one LIBO rate loan with effective ratesa total of 5.50% and 3.25%, respectively.
At December 31, 2015, the Company had $86.0$11 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of 3.36%, and $9$64 million was available for future borrowings.
Effective January 20, 2023, in lieu of a formal amendment, a borrowing base letter authorized by all lenders and the Company of the 2022 Credit Agreement resulted in an adjustment to decrease the amount of the Borrowing Base available from $75 million to $60 million until such time as the next redetermination date as required by the agreement.
Effective July 24, 2023, in lieu of a formal amendment, a borrowing base letter authorized by all lenders and the Company of the 2022 Credit Agreement resulted in an adjustment to increase the amount of the Borrowing Base available from $60 million to $65 million until such time as the next redetermination date as required by the agreement.
As of December 31, 2023, the borrowing base was $65 million and the Company had no outstanding borrowings under the Credit Facility.
Effective February 9, 2024, the Company and its lenders entered into the Second Amendment to the 2022 Credit Agreement. This amendment included an increase of the Borrowing Base from $65 million to $85 million and will remain in effect until the next scheduled redetermination date in accordance with the Credit Agreement. As of March 31, 2024 the Company had $4 million of outstanding borrowings and $81 million available under the credit facility.
5. Other Long-Term Obligations and Commitments:
Operating Leases:
The combinedCompany leases office facilities under operating leases and recognizes lease expense on a straight-line basis over the lease term. Lease assets and liabilities are initially recorded at commencement date based on the present value of lease payments over the lease term. As most of the Company’s lease contracts do not provide an implicit discount rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The weighted average interestdiscount rate paidused was 6.96%. Certain leases may contain variable costs above the minimum required payments and are not included in the right-of-use assets or liabilities. Leases may include renewal, purchase or termination options that can extend or shorten the term of the lease. The exercise of those options is at the Company’s sole discretion and is evaluated at inception and throughout the contract to determine if a modification of the lease term is required. Leases with an initial term of 12 months or less are not recorded on outstanding bank borrowings subject to base rate and LIBO interest was 3.44%the balance sheet.
Operating lease costs for the yearyears ended December 31, 2015, as compared to 3.53%2023 and 2022 were $700 thousand and $628 thousand, respectively. Cash payments included in the operating lease cost for the yearyears ended December 31, 2014.
2023 and 2022 were $739 thousand and $673 thousand, respectively. The Company entered into interest rate hedge agreements to help manage interest rate exposure. These contracts include interest rate swaps. Interest rate swap transactions generally involveweighted-average remaining operating lease terms for the exchange of fixed and floating rate interest payment obligations without the exchange of the underlying principal amounts. In July 2012, the Company entered into interest swap agreements for a period of two years which commenced in January 2014, related to $75 million of the Company’s bank debt resulting in a LIBO fixed rate of 0.563% and terminated in January 2016. For the year ended December 31, 2015,2023 and 2022 were 11 months and 11 months, respectively. As of 2023, the Company recorded interest expensehad certain leases for office space in Texas which included future payments of $275,000 in 2024 and paid $284,000 related to the settlement of interest rate swaps.$45,000 in 2025.
Equipment Loans:
On July 31, 2013,March 4, 2024 the Company entered into a $10.0 million Loan and Security Agreementtwelve-month lease extension agreement, effective March 1, 2024, with JP Morgan Chase Bank (“Equipment Loan”). The Equipment Loan is secured by a portionthe landlord of the Company’s field service equipment, carries an interest rate of 3.95% per annum, requires monthly payments (principal and interest) of $184,000, and has a final maturity date of July 31, 2018. As of December 31, 2015, the Company had a total of $5.58 million outstanding on this Equipment Loan.
On July 29, 2014, the Company entered into additional equipment financing facilities (“Additional Equipment Loans”) totaling $6.0 million with JP Morgan Chase Bank. In August 2014, the Company drew down $4.8 million of this facility that is secured by field service equipment, carries an interest rate of 3.40% per annum, requires monthly payments (principal and interest) of $87,800, and has a final maturity date of July 31, 2019. The remaining $1.2 million under the Additional Equipment Loans was available for interim draws to finance the acquisition of any future field service equipment. In December 2014, the Company made an interim draw of an additional $0.5 million on this facility that is secured by recently purchased field service equipment. Interim draws on this facility carried a floating interest rate, payable monthly at the LIBO published rate plus 2.50% and on June 26, 2015 converted into a fixed term loan requiring monthly payments (principal and interest) of $8,700 with a final maturity date of June 26, 2020. As of December 31, 2015, the Company had a total of $4.06 million outstanding on the Additional Equipment Loans.
6. Commitments
Operating Leases:
The Company has several non-cancelable operating leases, primarily for rental of office space, that have a term of more than one year. The future minimum lease payments for the operating leases at December 31, 2015 are as follows.
(Thousands of dollars) | Operating Leases | |||
2016 | $ | 793 | ||
2017 | 125 | |||
2018 | 16 | |||
|
| |||
Total minimum payments | $ | 934 | ||
|
| |||
Company's Houston office. Rent expense for office space for the years ended December 31, 20152023 and 20142022 was $786,000$767,000 and $785,000,$755,000, respectively.
The payment schedule for the Company’s operating lease obligations as of December 31, 2023 is as follows:
(Thousands of dollars) | Operating | |||
2024 | 275 | |||
2025 | 45 | |||
Total undiscounted lease payments | $ | 320 | ||
Less: Amount associated with discounting | (36 | ) | ||
Total net operating lease liabilities | $ | 284 | ||
Less: Current portion included in Current portion of Asset Retirement and Other Long-Term Obligations | 246 | |||
Non-current portion included in Other Long-Term Obligations | $ | 38 | ||
Asset Retirement Obligation:
A reconciliation of the liability for plugging and abandonment costs for the years ended December 31, 20152023 and 20142022 is as follows:
| Year Ended December 31, | Years Ended | |||||||||||||||
(Thousands of dollars) | 2015 | 2014 | 2023 | 2022 | ||||||||||||
Asset retirement obligation at beginning of period | $ | 12,501 | $ | 10,537 | $ | 15,443 | $ | 14,295 | ||||||||
Liabilities incurred | 28 | 1,627 | ||||||||||||||
(Gain) loss on settlement of obligations | — | (1,797 | ) | |||||||||||||
Net wells placed on production | 254 | 11 | ||||||||||||||
Liabilities settled | (1,112 | ) | (1,074 | ) | (2,706 | ) | (1,407 | ) | ||||||||
Dispositions | (1,161 | ) | (344 | ) | ||||||||||||
Accretion expense | 517 | 370 | 684 | 667 | ||||||||||||
Revisions in estimated liabilities | (197 | ) | 2,838 | 2,639 | 2,221 | |||||||||||
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Asset retirement obligation at end of period | $ | 11,737 | $ | 12,501 | $ | 15,153 | $ | 15,443 | ||||||||
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| |||||||||||||||
Less: Current portion included in Current portion of asset retirement and other long-term obligations | 446 | 1,918 | ||||||||||||||
Long-term Asset Retirement Obligations included in Asset Retirement Obligations | $ | 14,707 | $ | 13,525 | ||||||||||||
The Company’s liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive life of wells and a risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Revisions to the asset retirement obligation are recorded with an offsetting change to producing properties, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long life of most of the Company’s wells, the costs to ultimately retire the wells may vary significantly from previous estimates. In 2014, the Company recognized a gain on the settlement of asset retirement obligations associated with insurance recoveries related to obligations previously recognized on the plugging and abandonment of a well. During 2014 revisions in estimated liabilities for asset retirement obligations resulted from increased field costs resulting in shorter productive life of marginal wells and the enactment of new federal regulation requirements for plugging and abandonment.
7.
6. Contingent Liabilities
The Company, as managing general partner of the affiliated Partnerships, is responsible for all Partnership activities, including the drilling of development wells and the production and sale of oil and gas from productive wells. The Company also provides the administration, accounting and tax preparation work for the Partnerships, and is liable for all debts and liabilities of the affiliated Partnerships, to the extent that the assets of a given limited Partnership are not sufficient to satisfy its obligations.
The Company is subject to environmental laws and regulations. Management believes that future expenses, before recoveries from third parties, if any, will not have a material effect on the Company’s financial condition. This opinion is based on expenses incurred to date for remediation and compliance with laws and regulations, which have not been material to the Company’s results of operations.
From time to time, the Company is party to certain legal actions arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on the financial position or results of operations of the Company.
8.
7. Stock Options and Other Compensation
In May 1989, non-statutory stock options were granted by the Company to four key executive officers for the purchase of shares of common stock. At December 31, 20152023 and 2014,2022, options on 767,500 shares were outstanding and exercisable at prices ranging from $1.00 to $1.25. According to their terms, the options have no expiration date.
9.
8. Income Taxes
The components of the provision (benefit) for income taxes for the years ended December 31, 20152023 and 20142022 are as follows:
| Year Ended December 31, | Years Ended | |||||||||||||||
(Thousands of dollars) | 2015 | 2014 | 2023 | 2022 | ||||||||||||
Current: | ||||||||||||||||
Federal | $ | 27 | $ | 345 | $ | (891 | ) | $ | 8,330 | |||||||
State | (237 | ) | 262 | (258 | ) | 774 | ||||||||||
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| |||||||||||||||
Total current | (210 | ) | 607 | (1,149 | ) | 9,104 | ||||||||||
Deferred: | ||||||||||||||||
Federal | (6,330 | ) | 13,134 | 6,544 | 886 | |||||||||||
State | (108 | ) | 103 | 724 | 339 | |||||||||||
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| |||||||||||||||
Total deferred | (6,438 | ) | 13,237 | 7,268 | 1,225 | |||||||||||
|
| |||||||||||||||
Total income tax (benefit) provision | $ | (6,648 | ) | $ | 13,844 | |||||||||||
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| |||||||||||||||
Total income tax provision | $ | 6,119 | $ | 10,329 | ||||||||||||
(Thousands of dollars) Current Assets: Accrued liabilities Allowance for doubtful accounts Derivative contracts Total current assets Current Liabilities: Derivative contracts Total current liabilities Net current deferred income tax liabilities (assets) Non-Current Assets: Alternative minimum tax credits Net operating loss carry-forwards Percentage depletion carry-forwards Total non-current assets Non-Current Liabilities: Basis differences relating to managed partnerships Depletion and depreciation Total non-current liabilities Net non-current deferred income tax liabilities At December 31, 2015 2014 $ 593 $ 610 188 124 3 52 784 786 250 6,333 250 6,333 $ (534 ) $ 5,547 $ 5,319 $ 5,722 575 620 3,751 3,959 9,645 10,301 6,238 4,300 41,290 44,192 47,528 48,492 $ 37,884 $ 38,191
At December 31, | ||||||||
(Thousands of dollars) | 2023 | 2022 | ||||||
Deferred Tax Assets: | ||||||||
Accrued liabilities | $ | 349 | $ | 353 | ||||
Allowance for doubtful accounts | 154 | 77 | ||||||
Derivative Contracts | - | 223 | ||||||
Partnership basis difference | 106 | 90 | ||||||
State Net operating loss carry-forwards | 278 | 283 | ||||||
Total deferred tax assets | 887 | 1,026 | ||||||
Deferred Tax Liabilities: | ||||||||
Depletion and depreciation | 48,123 | 40,994 | ||||||
Total deferred tax liabilities | 48,123 | 40,994 | ||||||
Net deferred tax liabilities | $ | 47,236 | $ | 39,968 | ||||
The total provision for income taxes for the years ended December 31, 20152023 and 20142022 varies from the federal statutory tax rate as a result of the following:
| Year Ended December 31, | Years Ended | |||||||||||||||
(Thousands of dollars) | 2015 | 2014 | 2023 | 2022 | ||||||||||||
Expected tax expense | $ | (6,607 | ) | $ | 13,902 | $ | 7,187 | $ | 12,389 | |||||||
Permanent differences | 221 | 870 | ||||||||||||||
State income tax, net of federal benefit | (228 | ) | 254 | 204 | 612 | |||||||||||
Percentage depletion | (200 | ) | (312 | ) | ||||||||||||
Provision to return adjustment | (1,534 | ) | (3,540 | ) | ||||||||||||
Other, net | 387 | — | 41 | (2 | ) | |||||||||||
|
| |||||||||||||||
Total income tax provision | $ | (6,648 | ) | $ | 13,844 | $ | 6,119 | $ | 10,329 | |||||||
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Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes.
The Company is entitled to percentage depletion on certain of its wells, which is calculated without reference to the basis of the property. To the extent that such depletion exceeds a property’s basis, it creates a permanent difference, which lowers the Company’s effective rate. The availability of the percentage depletion deduction is phased out as an entity’s production exceeds certain levels, and based on the Company’s increasing production the percentage depletion deduction is becoming less significant.
The Company has $5.319 million in alternative minimum tax (“AMT”) credits which can be used to lower the regular
tax liability to the tentative AMT amount in years where the tentative AMT amount is less. These credits do not expire.
The Company is allowed a credit against the Texas Franchise Tax based on net operating losses incurred in prior periods. The credits allowed are $26 thousand in the years 2015 and 2016, and $89 thousand in the years 20172023 through 2026. Any credits not utilized in a given year due to the allowable credit exceeding the tax liability may be carried forward. No credit may be carried forward past 2026. The value of the credit is showncalculated net of the federal income tax effect.
The Company has not recorded any provision for uncertain tax positions. The Company files income tax returns in the U.S. federal jurisdiction and various state and local jurisdictions. The 2004, 2005, 2006, 2009 and 20092017 federal income tax returns have been audited by the Internal Revenue Service, while the 2012, 2013 and 2014 returns remain open for examination.Service. Returns for unexamined earlier years may be examined and adjustments made to the amount of percentage depletion and AMT credit carryforwards flowing from those years into an open tax year, although in general no assessment of income tax may be made for those years on which the statute has closed. Federal and State returns for the years 2012, 2013 and 20142020 through 2022 remain open for examination by the relevant taxing authorities.
Enactment of the Inflation Reduction Act of 2022.
10.
On August 16, 2022, President Biden signed into law the Inflation Reduction Act of 2022 (the “IRA”), which includes, among other things, a corporate alternative minimum tax (the “CAMT”). Under the CAMT, a 15 percent minimum tax will be imposed on certain adjusted financial statement income of “applicable corporations,” which is effective for tax years beginning after December 31, 2022. The CAMT generally treats a corporation as an “applicable corporation” in any taxable year in which the “average annual adjusted financial statement income” of the corporation and certain of its subsidiaries and affiliates for a three taxable-year period ending prior to such taxable year exceeds $1 billion. The IRA also establishes a one percent excise tax on stock repurchases made by publicly traded U.S. corporations. The excise tax is effective for any stock repurchases after December 31, 2022. The value of share repurchases subject to the excise tax is reduced by the fair market value of any shares issued during the tax year, including the fair market value of any shares issued or provided to employees or specified affiliates. During the year ended December 31, 2023, the Company recorded $74 thousand related to the IRA excise tax payable on share repurchases.
9. Segment Information and Major Customers
The Company operates in one industry—industry – oil and gas exploration, development, operation and servicing. The Company’s oil and gas activities are entirely in the United States.
The Company sells its oil and natural gas and liquids production to a number of purchasers.direct purcchasers under direct contracts or through other operators under joint operating agreements. Listed below are the percentpurchasers of the Company’s total oil and gas sales made to each of the customers whose purchasesproduction which represented more than 10% of the Company’s oilsales for the years ended 2023 and gas sales in the year 2015.2022.
Oil Purchasers: | Gas Purchasers: | |||||||||
Plains All American Inc. | 43.55 | % | Targa Pipeline Mid-Continent | 23.27 | % | |||||
Sunoco, Inc. | 24.92 | % | ||||||||
Primexx Energy Corporation | 10.90 | % |
2023 | 2022 | |||||||
Oil: | ||||||||
APA Corporation | 22 | % | 55 | % | ||||
Civitas Resources Inc. | 20 | % | -- | % | ||||
Plains All American Inc. | 19 | % | 16 | % | ||||
DE IV Operating, LLC. | 14 | % | -- | % | ||||
Natural gas and liquids: | ||||||||
APA Corporation | 17 | % | 58 | % | ||||
Civitas Resources Inc. | 10 | % | -- | % | ||||
Targa Pipeline Mid-Continent West Tex, LLC | -- | % | 11 | % | ||||
Although there are no long-term oil and gas purchasing agreements with these purchasers, the Company believes that they will continue to purchase its oil and gas products and, if not, could be replaced by other purchasers.
11.
10. Financial Instruments
Fair Value Measurements:
Authoritative guidance on fair value measurements defines fair value, establishes a framework for measuring fair value and stipulates the related disclosure requirements. The Company follows a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value. The fair values of the Company’s interest rate swaps, natural gas and crude oil price collars and swaps are designated as Level 3. The following fair value hierarchy table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis at December 31, 2015 and 2014:2022:
December 31, 2015 (Thousands of dollars) | Quoted Prices in Active Markets For Identical Assets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Balance at December 31, 2015 | ||||||||||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||||||
Interest rate derivative contracts | $ | — | $ | — | $ | (7 | ) | $ | (7 | ) | ||||||||||||||||||||||
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Total liabilities | $ | — | $ | — | $ | (7 | ) | $ | (7 | ) | ||||||||||||||||||||||
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December 31, 2014 (Thousands of dollars) | Quoted Prices in Active Markets For Identical Assets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | Balance at December 31, 2014 | ||||||||||||||||||||||||||||
December 31, 2022 | Quoted Prices in | Significant | Significant | Balance at | ||||||||||||||||||||||||||||
(Thousands of dollars) | ||||||||||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||||||
Commodity derivative contracts | $ | — | $ | — | $ | 16,901 | $ | 16,901 | $ | — | $ | — | $ | 210 | $ | 210 | ||||||||||||||||
Interest rate derivative contracts | — | — | 26 | 26 | ||||||||||||||||||||||||||||
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Total assets | $ | — | $ | — | $ | 16,927 | $ | 16,927 | $ | — | $ | — | $ | 210 | $ | 210 | ||||||||||||||||
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Liabilities | ||||||||||||||||||||||||||||||||
Interest rate derivative contracts | $ | — | $ | — | $ | (170 | ) | $ | (170 | ) | ||||||||||||||||||||||
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Commodity derivative contract | $ | — | $ | — | $ | (1,190 | ) | $ | (1,190 | ) | ||||||||||||||||||||||
Total liabilities | $ | — | $ | — | $ | (170 | ) | $ | (170 | ) | $ | — | $ | — | $ | (1,190 | ) | $ | (1,190 | ) | ||||||||||||
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The derivative contracts were measured based on quotes from the Company’s counterparties. Such quotes have been derived using valuation models that consider various inputs including current market and contractual prices for the underlying instruments, quoted forward prices for natural gas and crude oil, volatility factors and interest rates, such as a LIBOR curve for a similar length of time as the derivative contract term as applicable.
These estimates are verified using comparable NYMEX futures contracts or are compared to multiple quotes obtained from counterparties for reasonableness.
The significant unobservable inputs for Level 3 derivative contracts include basis differentials and volatility factors. An increase (decrease) in these unobservable inputs would result in an increase (decrease) in fair value, respectively. The Company does not have access to the specific assumptions used in its counterparties’ valuation models. Consequently, additional disclosures regarding significant Level 3 unobservable inputs were not provided.
The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the yearsyear ended December 31, 2015 and 2014.2023.
| Year Ended December 31, | ||||||||
(Thousands of dollars) | 2015 | 2014 | ||||||
Net assets (liabilities) at beginning of period | $ | 16,757 | $ | (865 | ) | |||
Total realized and unrealized gains (losses): | ||||||||
Included in earnings (a) | 3,966 | 17,420 | ||||||
Included in other comprehensive income (loss) | 137 | 48 | ||||||
Purchases, sales, issuances and settlements | (20,867 | ) | 154 | |||||
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Net assets (liabilities) at end of period | $ | (7 | ) | $ | 16,757 | |||
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| |||||
(Thousands of dollars) | ||||
Net Liabilities – December 31, 2022 | $ | (980 | ) | |
Total realized and unrealized gains | 980 | |||
Net Liabilities – December 31, 2023 | $ | — |
(a) | Derivative instruments are reported in revenues as realized gain/loss and on a separately reported line item captioned unrealized gain/loss on derivative |
Derivative Instruments:
The Company is exposed to commodity price and interest rate risk, and management considers periodically the Company’s exposure to cash flow variability resulting from the commodity price changes and interest rate fluctuations. Futures, swaps and options are used to manage the Company’s exposure to commodity price risk inherent in the Company’s oil and gas production operations. The Company does not apply hedge accounting to any of its commodity basedcommodity-based derivatives. Both realized and unrealized gains and losses associated with commodity derivative instruments are recognized in earnings.
Interest rate swap derivatives continue to be treated as cash-flow hedges and are used to fix our float interest rates on existing debt. The value of these interest rate swaps at December 31, 2015 and 2014 are located in accumulated other comprehensive loss, net of tax. Settlement of the swaps, which began in January 2014, are recognized within interest expense.
The following table sets forth the effect of derivative instruments on the consolidated balance sheets at December 31, 20152023 and 2014:2022:
| Fair Value at December 31, | Fair Value | ||||||||||||||||||
(Thousands of dollars) | Balance Sheet Location | 2015 | 2014 | Balance Sheet Location | December 31, | December 31, | |||||||||||||
Asset Derivatives: | |||||||||||||||||||
Derivatives designated as cash-flow hedging instruments: | |||||||||||||||||||
Interest rate swap contracts | Derivative contracts | $ | — | $ | 12 | ||||||||||||||
Interest rate swap contracts | Derivative contracts long-term | — | 13 | ||||||||||||||||
Derivatives not designated as cash-flow hedging instruments: | |||||||||||||||||||
Crude oil commodity contract | Other current assets | $ | — | $ | 162 | ||||||||||||||
Natural gas commodity contract | Other current assets | — | 48 | ||||||||||||||||
Total | Total | $ | — | $ | 210 | ||||||||||||||
Liability Derivatives: | |||||||||||||||||||
Derivatives not designated as cash-flow hedging instruments: | |||||||||||||||||||
Crude oil commodity contracts | Derivative contracts | — | 14,629 | Derivative liability short-term | $ | — | $ | (931 | ) | ||||||||||
Natural gas commodity contracts | Derivative contracts | — | 2,273 | Derivative liability short-term | — | (259 | ) | ||||||||||||
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Total | $ | — | $ | 16,927 | Total | $ | — | $ | (1,190 | ) | |||||||||
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Liability Derivatives: | |||||||||||||||||||
Derivatives designated as cash-flow hedging instruments: | |||||||||||||||||||
Interest rate swap contracts | Derivative liability short-term | $ | (7 | ) | $ | (170 | ) | ||||||||||||
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Total | $ | (7 | ) | $ | (170 | ) | |||||||||||||
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Total derivative instruments | $ | (7 | ) | $ | 16,757 | Total derivative instruments | $ | — | $ | (980 | ) | ||||||||
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The following table sets forth the effect of derivative instruments on the consolidated statements of operationsincome for the years ended December 31, 20152023 and 2014:2022:
| Location of gain/loss recognized | Amount of gain/loss recognized in income | |||||||||
(Thousands of dollars) | in income | 2015 | 2014 | |||||||
Derivative designated as cash-flow hedge instruments: | ||||||||||
Interest rate swap contracts | Interest expense | $ | (284 | ) | $ | (289 | ) | |||
Derivatives not designated as cash-flow hedge instruments: | ||||||||||
Natural gas commodity contracts | Unrealized (loss) gain on derivative instruments, net | (2,273 | ) | 2,542 | ||||||
Crude oil commodity contracts | Unrealized (loss) gain on derivative instruments, net | (14,628 | ) | 15,032 | ||||||
Natural gas commodity contracts (a) | Realized gain (loss) on derivative instruments, net | 3,017 | (529 | ) | ||||||
Crude oil commodity contracts (a) | Realized gain on derivative instruments, net | 18,134 | 664 | |||||||
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| $ | 3,966 | $ | 17,420 | |||||||
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Amount of gain/loss (Thousands of dollars) 2023 2022 Derivatives not designated as cash-flow hedge instruments: Natural gas commodity contracts Unrealized gain on derivative instruments, net Crude oil commodity contracts Unrealized gain on derivative instruments, net Natural gas commodity contracts Realized gain (loss) on derivative instruments, net Crude oil commodity contracts Realized gain (loss) on derivative instruments, net ) $
recognized in income Location of gain/loss recognized in income — 892 — 3,713 235 (4,543 ) 179 (12,101 $ 414 (12,039 )
12.11. Related Party Transactions
The Company, as managing general partner
Amounts due to or managing trustee, makes an annual offer to repurchase the interests of the partners and trust unit holders in certain of the Partnerships or Trusts. The Company purchased such interests in an amount totaling $409,000 during 2015 and $274,000 during 2014.
Treasury stock purchases in any reported period may include shares from a related party. There were no related party treasury stock purchases during the years ended December 31, 2015 and 2014.
Receivables from related parties consist of reimbursable general and administrative costs, lease operating expenses and reimbursement for property development and related costs. These receivables are due from joint venture partners, which may include members of the Company’s Board of Directors.
Payables owed to related parties primarily represent receipts or expenses, related to oil and gas properties, collected or paid by the Company as agent for the joint venture partners, which may include members of the Company’s Board of Directors, for oil and gas sales net of expenses.Directors.
13. Restricted Cash and Cash Equivalents
Restricted cash and cash equivalents include $3.51 million and $3.88 million at December 31, 2015 and 2014, respectively, of cash primarily pertaining to oil and gas revenue payments. There were corresponding accounts payable recorded at December 31, 2015 and 2014 for these liabilities. Both the restricted cash and the accounts payable are classified as current on the accompanying consolidated balance sheets.
14.12. Salary Deferral Plan
The Company maintains a salary deferral plan (the “Plan”) in accordance with Internal Revenue Code Section 401(k), as amended. The Plan provides for matching contributions, of which $577,000$362,756 and $591,000$301,837 were made in 20152023 and 2014,2022, respectively.
15.13. Earnings per Share
Basic earnings per share are computed by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share reflect per share amounts that would have resulted if dilutive potential common stock had been converted to common stock in gain periods. The following reconciles amounts reported in the consolidated financial statements:
| Year Ended December 31, | Years Ended December 31, | |||||||||||||||||||||||||||||||||||||||||||||||
| 2015 | 2014 | 2023 | 2022 | |||||||||||||||||||||||||||||||||||||||||||||
| Net Loss (In 000’s) | Weighted Average Number of Shares Outstanding | Per Share Amount | Net Income (In 000’s) | Weighted Average Number of Shares Outstanding | Per Share Amount | Net Income | Weighted | Per Share | Net Income | Weighted | Per Share | |||||||||||||||||||||||||||||||||||||
Basic | $ | (12,784 | ) | 2,312,810 | $ | (5.53 | ) | $ | 27,046 | 2,361,134 | $ | 11.45 | $ | 28,103 | 1,849,780 | $ | 15.19 | $ | 48,664 | 1,953,916 | $ | 24.91 | ||||||||||||||||||||||||||
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Effect of dilutive securities: | ||||||||||||||||||||||||||||||||||||||||||||||||
Options | — | — | — | — | 753,897 | — | 759,006 | — | 757,254 | |||||||||||||||||||||||||||||||||||||||
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Diluted (a) | $ | (12,784 | ) | 2,312,810 | $ | (5.53 | ) | $ | 27,046 | 3,115,031 | $ | 8.68 | ||||||||||||||||||||||||||||||||||||
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| |||||||||||||||||||||||||||||||||||||||||||
Diluted | $ | 28,103 | 2,608,786 | $ | 10.77 | $ | 48,664 | 2,711,170 | $ | 17.95 | ||||||||||||||||||||||||||||||||||||||
16. Shareholder’s Equity
The Company has in place a stock repurchase program whereby it may purchase outstanding shares of its common stock from time-to-time, in open market transactions or negotiated sales. The Company uses the cost method to account for its treasury share purchases.
PRIMEENERGY RESOURCES CORPORATION AND SUBSIDIARIES
SUPPLEMENTARY INFORMATION
OIL AND GAS PRODUCING ACTIVITIES
Years Ended December 31, 2015 and 2014
(Unaudited)
| As of December 31, | As of December 31, | |||||||||||||||
(Thousands of dollars) | 2015 | 2014 | 2023 | 2022 | ||||||||||||
Proved Developed oil and gas properties | $ | 395,129 | $ | 395,314 | $ | 659,792 | $ | 555,280 | ||||||||
Proved Undeveloped oil and gas properties | — | 1,274 | — | — | ||||||||||||
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| |||||||||||||||
Total Capitalized Costs | 395,129 | 396,588 | 659,792 | 555,280 | ||||||||||||
Accumulated depreciation, depletion and valuation allowance | 204,213 | 188,988 | (406,913 | ) | (385,811 | ) | ||||||||||
|
| |||||||||||||||
Net Capitalized Costs | $ | 190,916 | $ | 207,600 | $ | 252,879 | $ | 169,469 | ||||||||
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| |||||||||||||||
COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION,
EXPLORATION AND DEVELOPMENT ACTIVITIES
Years Ended December 31, 2015 and 2014
(Unaudited)
| Year Ended December 31, | Years Ended December 31, | |||||||||||||||
(Thousands of dollars) | 2015 | 2014 | 2023 | 2022 | ||||||||||||
Acquisition of Properties, Developed | — | $ | 59 | |||||||||||||
Development Costs | $ | 14,550 | 36,406 | $ | 110,700 | $ | 13,598 | |||||||||
STANDARDIZED MEASURE OF DISCOUNTED FUTURE
NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES
Years Ended December 31, 2015 and 2014
(Unaudited)
| As of December 31, | As of December 31, | |||||||||||||||
(Thousands of dollars) | 2015 | 2014 | 2023 | 2022 | ||||||||||||
Future cash inflows | $ | 293,745 | $ | 2,252,248 | $ | 1,219,605 | $ | 994,842 | ||||||||
Future production costs | (191,227 | ) | (738,531 | ) | (437,408 | ) | (378,160 | ) | ||||||||
Future development costs | (30,586 | ) | (354,139 | ) | (213,823 | ) | (95,746 | ) | ||||||||
Future income tax expenses | (4,815 | ) | (360,702 | ) | (119,359 | ) | (110,439 | ) | ||||||||
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| |||||||||||||||
Future Net Cash Flows | 67,117 | 798,876 | 449,015 | 410,497 | ||||||||||||
10% annual discount for estimated timing of cash flows | (8,315 | ) | (455,588 | ) | (170,967 | ) | (165,961 | ) | ||||||||
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| |||||||||||||||
Standardized Measure of Discounted Future Net Cash Flows | $ | 58,802 | $ | 343,288 | $ | 278,048 | $ | 244,536 | ||||||||
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| |||||||||||||||
See accompanying Notes to Supplementary Information
PRIMEENERGY RESOURES CORPORATION AND SUBSIDIARIES
SUPPLEMENTARY INFORMATION
STANDARDIZED MEASURE OF DISCOUNTED FUTURE
NET CASH FLOWS AND CHANGES THEREIN
RELATING TO PROVED OIL AND GAS RESERVES
Years Ended December 31, 2015 and 2014
(Unaudited)
The following are the principal sources of change in the standardized measure of discounted future net cash flows during 20152023 and 2014:2022:
| Year Ended December 31, | Years Ended | |||||||||||||||
(Thousands of dollars) | 2015 | 2014 | 2023 | 2022 | ||||||||||||
Sales of oil and gas produced, net of production costs | $ | (10,426 | ) | $ | (47,074 | ) | $ | (107,742 | ) | $ | (86,302 | ) | ||||
Net changes in prices and production costs | (511,116 | ) | (18,510 | ) | (98,132 | ) | 72,640 | |||||||||
Extensions, discoveries and improved recovery | 24,967 | 198,235 | 178,960 | 126,029 | ||||||||||||
Revisions of previous quantity estimates | (180,048 | ) | 67,245 | (3,877 | ) | (10,902 | ) | |||||||||
Net change in development costs | 235,285 | (69,923 | ) | 66,552 | (2,814 | ) | ||||||||||
Reserves sold | (1,160 | ) | (69 | ) | (398 | ) | (818 | ) | ||||||||
Reserves purchased | 737 | — | — | — | ||||||||||||
Accretion of discount | 34,329 | 23,823 | 24,454 | 13,581 | ||||||||||||
Net change in income taxes | 146,339 | (56,744 | ) | 4,532 | (8,435 | ) | ||||||||||
Changes in production rates (timing) and other | (23,393 | ) | 8,077 | (30,836 | ) | 5,751 | ||||||||||
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| |||||||||||||||
Net change | (284,486 | ) | 105,060 | 33,512 | 108,730 | |||||||||||
Standardized measure of discounted future net cash flow: | ||||||||||||||||
Beginning of year | 343,288 | 238,228 | 244,536 | 135,806 | ||||||||||||
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End of year | $ | 58,802 | $ | 343,288 | $ | 278,048 | $ | 244,536 | ||||||||
|
| |||||||||||||||
See accompanying Notes to Supplementary Information
PRIMEENERGY RESOURCES CORPORATION AND SUBSIDIARIES
SUPPLEMENTARY INFORMATION
Years Ended December31, 20152023 and 20142022
(Unaudited)
| As of December 31, | As of December 31, | |||||||||||||||||||||||||||||||||||||||||||||||
| 2015 | 2014 | 2023 | 2022 | |||||||||||||||||||||||||||||||||||||||||||||
| Oil (MBbls) | NGLs (MBbls) | Gas (MMcf) | Oil (MBbls) | NGLs (MBbls) | Gas (MMcf) | Oil | NGL’s | Gas | Oil | NGLs | Gas | |||||||||||||||||||||||||||||||||||||
Proved Developed Reserves: | ||||||||||||||||||||||||||||||||||||||||||||||||
Beginning of year | 6,239 | 2,160 | 32,267 | 6,687 | 2,223 | 31,628 | 4,143 | 2,497 | 22,277 | 5,386 | 2,882 | 23,902 | ||||||||||||||||||||||||||||||||||||
Extensions, discoveries and improved recovery | 47 | 85 | 2,067 | 186 | 222 | 424 | 843 | 467 | 2,391 | 99 | 74 | 464 | ||||||||||||||||||||||||||||||||||||
Revisions of previous estimates | (1,650 | ) | (560 | ) | (8,368 | ) | (278 | ) | (207 | ) | 3,662 | (1,101 | ) | (515 | ) | (4,796 | ) | (375 | ) | (37 | ) | 1,309 | ||||||||||||||||||||||||||
Converted from undeveloped reserves | 677 | 163 | 944 | 407 | 93 | 735 | 3,028 | 1,833 | 9,030 | — | — | — | ||||||||||||||||||||||||||||||||||||
Reserves sold | (53 | ) | — | (26 | ) | (4 | ) | — | — | (12 | ) | — | (26 | ) | (28 | ) | (5 | ) | (73 | ) | ||||||||||||||||||||||||||||
Reserves purchased | 39 | 12 | 372 | — | — | — | ||||||||||||||||||||||||||||||||||||||||||
Reserve purchased | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||
Production | (720 | ) | (187 | ) | (3,981 | ) | (759 | ) | (171 | ) | (4,182 | ) | (1,144 | ) | (606 | ) | (4,127 | ) | (939 | ) | (417 | ) | (3,325 | ) | ||||||||||||||||||||||||
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End of year | 4,579 | 1,673 | 23,275 | 6,239 | 2,160 | 32,267 | 5,757 | 3,676 | 24,749 | 4,143 | 2,497 | 22,277 | ||||||||||||||||||||||||||||||||||||
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| |||||||||||||||||||||||||||||||||||||||||||
Proved Undeveloped Reserves: | ||||||||||||||||||||||||||||||||||||||||||||||||
Beginning of year | 14,709 | 4,322 | 26,331 | 9,066 | 3,707 | 19,772 | 3,028 | 1,833 | 9,030 | — | — | — | ||||||||||||||||||||||||||||||||||||
Extensions, discoveries and improved recovery | 420 | 101 | 701 | 5,914 | 1,629 | 6,672 | 6,254 | 5,156 | 24,470 | 3,028 | 1,833 | 9,030 | ||||||||||||||||||||||||||||||||||||
Revisions of previous estimates | (14,400 | ) | (4,248 | ) | (26,033 | ) | 136 | (921 | ) | 622 | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||
Converted to developed reserves | (677 | ) | (163 | ) | (944 | ) | (407 | ) | (93 | ) | (735 | ) | (3,028 | ) | (1,833 | ) | (9,030 | ) | — | — | — | |||||||||||||||||||||||||||
Reserves sold | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||
Reserves purchased | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||
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Reserves Sold | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||
End of year | 52 | 12 | 55 | 14,709 | 4,322 | 26,331 | 6,254 | 5,156 | 24,470 | 3,028 | 1,833 | 9,030 | ||||||||||||||||||||||||||||||||||||
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|
| |||||||||||||||||||||||||||||||||||||||||||
Total Proved Reserves at the End of the Year | 4,631 | 1,685 | 23,330 | 20,948 | 6,482 | 58,598 | 12,011 | 8,832 | 49,219 | 7,171 | 4,330 | 31,307 | ||||||||||||||||||||||||||||||||||||
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RESULTS OF OPERATIONS FROM OIL AND GAS PRODUCING ACTIVITIES
Years Ended December31, 20152023 and 20142022
(Unaudited)
| Year Ended December 31, | Years Ended December 31, | |||||||||||||||
(Thousands of dollars) | 2015 | 2014 | 2023 | 2022 | ||||||||||||
Revenue: | ||||||||||||||||
Oil and gas sales | $ | 45,632 | $ | 91,045 | $ | 107,742 | $ | 124,118 | ||||||||
Costs and Expenses: | ||||||||||||||||
Lease operating expenses | 35,206 | 43,972 | 39,004 | 37,816 | ||||||||||||
Depreciation, depletion and accretion | 28,531 | 22,906 | 31,660 | 28,068 | ||||||||||||
Income tax (benefit) expense | (6,156 | ) | 9,216 | |||||||||||||
|
| |||||||||||||||
Income tax expense | 5,797 | 10,329 | ||||||||||||||
Total Costs and Expenses | 57,581 | 76,094 | 76,461 | 76,213 | ||||||||||||
|
| |||||||||||||||
Results of Operations From Producing Activities (excluding corporate overhead and interest costs) | $ | (11,949 | ) | $ | 14,951 | |||||||||||
|
| |||||||||||||||
Results of Operations from Producing Activities (excluding corporate overhead and interest costs) | $ | 31,281 | $ | 47,905 | ||||||||||||
See accompanying Notes to Supplementary Information
PRIMEENERGY RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO SUPPLEMENTARY INFORMATION
(Unaudited)
1. Presentation of Reserve Disclosure Information
Reserve disclosure information is presented in accordance with U.S. generally accepted accounting principles. The Company’s reserves include amounts attributable to non-controlling interests in the Partnerships. These interests represent less than 10% of the Company’s reserves.
2. Determination of Proved Reserves
The estimates of the Company’s proved reserves were determined by an independent petroleum engineer in accordance with U.S. generally accepted accounting principles. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development and other factors. Estimated future net revenues were computed by reserves, less estimated future development and production costs based on current costs.
Proved reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that proved reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.
3. Results of Operations from Oil and Gas Producing Activities
The results of operations from oil and gas producing activities were prepared in accordance with U.S. generally accepted accounting principles. General and administrative expenses, interest costs and other unrelated costs are not deducted in computing results of operations from oil and gas activities.
4. Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves
The standardized measure of discounted future net cash flows relating to proved oil and gas reserves and the changes of standardized measure of discounted future net cash flows relating to proved oil and gas reserves were prepared in accordance with U.S. generally accepted accounting principles.
Future cash inflows are computed as described in Note 2 by applying current prices to year-end quantities of proved reserves.
Future production and development costs are computed estimating the expenditures to be incurred in developing and producing the oil and gas reserves at year-end, based on year-end costs and assuming continuation of existing economic conditions.
Future income tax expenses are calculated by applying the year-end U.S. tax rate to future pre-tax cash inflows relating to proved oil and gas reserves, less the tax basis of properties involved. Future income tax expenses give effect to permanent differences and tax credits and allowances relating to the proved oil and gas reserves.
Future net cash flows are discounted at a rate of 10% annually (pursuant to applicable guidance) to derive the standardized measure of discounted future net cash flows. This calculation does not necessarily represent an estimate of fair market value or the present value of such cash flows since future prices and costs can vary substantially from year-end and the use of a 10% discount figure is arbitrary.
5. Changes in Reserves
The 20152023 and 20142022 extensions and discoveries reflect the successful drilling activity in the Company’s West Texas and Mid-Continent areas. The Company is employing technologies to establish proved reserves that have been demonstrated to provide consistent results capable of repetition. The technologies and economic data being used in the estimation of its proved reserves include, but are not limited to, electrical logs, radioactivity logs, geologic maps, production data and well test data. The estimated reserves of wells with sufficient production history are estimated using appropriate decline curves. Estimated reserves of producing wells with limited production history and for undeveloped locations are estimated using performance data from analogous wells in the area. These wells are considered analogous based on production performance from the same formation and with similar completion techniques. Future development plans are reflective of the significant decrease incurrent commodity prices and have been established based on an expectation of available cash flows from operations and availability under our revolving credit facility. As of December 31, 2015, we removed all but one PUD location from our year end reserve report due to the uncertainty of available capital for drilling expenditure. The PUD location included in the report was drilled in the first quarter of 2016.
F-23