•Marketing operating income decreased $9 million for the year ended December 31, 2023, compared to 2022, primarily due to a $7 million decrease in the marketing margin, as well as a $2 million increase in operating expenses associated with higher personnel related costs.
•Marketing revenues decreased in 2023, compared to 2022, primarily due to a 57% decrease in the price received for volumes marketed partially offset by a 37 Bcfe increase in marketed volumes.
•The margin generated from marketing activities decreased $7 million for the year ended December 31, 2023, as compared to the prior year, primarily due to a 57% decrease in the price received for volumes marketed partially offset by a 2% increase in volumes marketed.
Marketing
We attempt to capture opportunities related to the marketing and transportation of natural gas, oil and NGLs primarily involving the marketing of our own equity production and that of royalty owners in our wells. Additionally, we manage portfolio and locational, or basis, risk, acquire transportation rights on third-party pipelines and, in limited circumstances, purchase third-party natural gas to fulfill commitments specific to a geographic location.
Appalachia. Our transportation portfolio for all products in Appalachia is highly diversified, allows us to capitalize on strengthening markets, including city-gate markets, and provides production flow assurance. Agreements with Rover Pipeline LLC and Mountaineer Xpress / Gulf Xpress pipelines allow us to access growing high-demand markets in the U.S. Gulf Coast region while low-cost transportation on other northeast pipelines allows us to capture in-basin pricing, and our agreements with Rover Pipeline LLC and Rockies Express Pipeline LLC provide access to Midwest markets. In addition to our natural gas
transportation, we have ethane take-away capacity that provides direct access to Mont Belvieu pricing. Certain of our capacity agreements contain multiple extension and reduction options that allow us to right-size our transportation portfolio as needed for our production or to capture future market opportunities. The table below details our firm transportation, firm sales and total takeaway capacity over the next three years as of February 20, 2024:
| | | | | | | | | | | | | | | | | |
| For the year ended December 31, |
| (MMBtu/d) | 2024 | | 2025 | | 2026 |
Firm transportation (1) | 2,286,237 | | | 2,173,754 | | | 1,890,613 | |
| Firm sales | 515,676 | | | 149,988 | | | 74,949 | |
| Total firm takeaway – Appalachia | 2,801,913 | | | 2,323,742 | | | 1,965,562 | |
(1)We have extension options and potential contract renewal capacity of 125,000 MMBtu per day for 2024 and 278,500 MMBtu per day for 2025 for Appalachia.
Haynesville. Our transportation portfolio for Haynesville allows for access to the U.S. Gulf Coast and LNG corridor markets. Agreements with ETC Tiger, Gulf South and Enable Line CP provide transport to the Southeast Supply Header (“SESH”) and Perryville Hub, a central trading location with high demand and amply liquidity, while Acadian, Midcoast and LEAP pipelines deliver to the growing LNG corridor, with direct access to LNG shippers at sales prices close to Henry Hub pricing. Our diversified transportation portfolio provides flow optionality and allows for advantageous pricing year-round as the Haynesville maintains stability in basis throughout the year. The table below details our natural gas firm transportation, firm sales and total takeaway capacity over the next three years as of February 20, 2024:
| | | | | | | | | | | | | | | | | |
| For the year ended December 31, |
| (MMBtu/d) | 2024 | | 2025 | | 2026 |
Firm transportation (1) | 1,139,519 | | | 1,232,008 | | | 1,036,071 | |
| Firm sales | 2,072,188 | | | 1,766,376 | | | 1,535,343 | |
| Total firm takeaway – Haynesville | 3,211,707 | | | 2,998,384 | | | 2,571,414 | |
(1)We have extension options and potential contract renewal capacity of 200,000 MMBtu per day for 2024 and 200,000 MMBtu per day for 2025 for Appalachia.
Demand Charges
As of December 31, 2023, our obligations for demand and similar charges under the firm transportation agreements and gathering agreements totaled approximately $9.3 billion, $1,015 million of which related to access capacity on future pipeline and gathering infrastructure projects that still require the granting of regulatory approvals and additional construction efforts. We also have guarantee obligations of up to $808 million of that amount. We regularly monitor our proved reserves to ensure sufficient availability to fully utilize our firm transportation commitments.
We refer you to Note 10 to the consolidated financial statements included in this Annual Report for further details on our demand charges and the risk factor “Our business depends on access to natural gas, oil and NGL gathering, processing and transportation systems and facilities. Changes to access and cost of these systems and facilities could adversely impact our business and financial condition. Our commitments to assure availability of transportation could lead to substantial payments for capacity we do not use if production falls below projected levels,” in Item 1A of Part I of this Annual Report. Competition
Our marketing activities compete with numerous other companies offering the same services, many of which possess larger financial and other resources than we have. Some of these competitors are other producers and affiliates of companies with extensive pipeline systems that are used for transportation from producers to end users. Other factors affecting competition are the cost and availability of alternative fuels, the level of consumer demand and the cost of and proximity to pipelines and other transportation facilities. We believe that our ability to compete effectively within the marketing segment in the future depends upon establishing and maintaining strong relationships with customers.
Customers
Our marketing customers include LNG exporters, major energy companies, utilities and industrial purchasers of natural gas. For the year ended December 31, 2023, one purchaser accounted for 14% of our revenues. A default or operational disruption on this account could have a material impact on the Company. For the year ended December 31, 2022, one purchaser accounted for 17% of our revenues. No other purchasers accounted for more than 10% of consolidated revenues.
Regulation
The transportation of natural gas, oil and NGLs is heavily regulated. FERC regulates the rates and the terms and conditions of transportation service provided by interstate natural gas, crude oil and NGL pipelines. State governments typically must authorize the construction of pipelines for intrastate service. Moreover, the rates charged for intrastate transportation by pipeline are subject to regulation by state regulatory commissions. The basis for intrastate pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate pipeline rates, varies from state to state. Currently, all pipelines we own are intrastate and immaterial to our operations.
State and local permitting, zoning and land use regulations can affect the location, construction and operation of gathering and other pipelines needed to transport production to market, and the lack of new pipeline capacity can limit our ability to reach relevant markets for the sale of the commodities we produce.
The transportation of natural gas and oil is also subject to extensive environmental regulation. We refer you to “Other – Environmental Regulation” in Item 1 of Part I of this Annual Report and the risk factor “We, our service providers and our customers are subject to complex federal, state and local laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities” in Item 1A of Part I of this Annual Report for a discussion of the impact of environmental regulation on our business. Other
We currently have no significant business activity outside of our E&P and Marketing segments.
Environmental Regulation
General. Our operations are subject to laws and regulations governing protection of the environment and natural resources in the jurisdictions in which we operate. These laws and regulations require permits for drilling wells and the maintenance of bonding requirements to drill or operate wells, and also regulate the spacing and location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells and the prevention and cleanup of pollutants and other matters. We maintain insurance for clean-up costs in limited instances arising out of sudden and accidental events, but otherwise we may not be fully insured against all such risks. Although future environmental obligations are not expected to have a material impact on the results of our operations or financial condition, there can be no assurance that future developments, such as increasingly stringent environmental laws or enforcement thereof, will not cause us to incur material environmental liabilities or costs.
Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal fines and penalties and the imposition of injunctive relief. Certain laws and legal principles can make us liable for environmental damage to properties we previously owned, and, although we generally require purchasers to assume that liability, there is no assurance that they will have sufficient funds should a liability arise. Changes in environmental laws and regulations occur frequently, and any changes may result in more stringent and costly waste handling, storage, transportation, disposal or cleanup requirements. We do not expect continued compliance with existing requirements to have a material adverse impact on us, but there can be no assurance that this will continue in the future. We refer you to “Other – Environmental Regulation” in Item 1 of Part 1 of this Annual Report and the risk factor “We, our service providers and our customers are subject to complex federal, state and local laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities” in Item 1A of Part I of this Annual Report for a discussion of the impact of environmental regulation on our business. The following is a summary of the more significant existing environmental and worker health and safety laws and regulations to which we are subject.
Generation and Disposal of Wastes. The Comprehensive Environmental Response, Compensation, and Liability Act, as amended, also known as CERCLA or the “Superfund law,” imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current or former owner or operator of a site where the release occurred, as well as persons that transported or disposed, or arranged for the transportation or disposal of, the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to strict, joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.
The Resource Conservation and Recovery Act, as amended, or RCRA, generally does not regulate wastes generated by the exploration and production of natural gas and oil. RCRA specifically excludes from the definition of hazardous waste “drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy.” However, legislative and regulatory initiatives have been considered from time to time that would reclassify certain natural gas and oil exploration and production wastes as “hazardous wastes,” which would make the reclassified wastes subject to more stringent handling, disposal and clean-up requirements. If such measures were enacted, it could have a significant impact on our operating costs.
The Clean Water Act, as amended, or CWA, and analogous state laws, impose restrictions and strict controls regarding the discharge of produced waters and other natural gas and oil waste into waters of the United States (“WOTUS”). Permits must be obtained to discharge pollutants to, and to conduct construction activities in, WOTUS. The CWA and similar state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges of reportable quantities of oil and other hazardous substances. The U.S. Environmental Protection Agency (“EPA”) has adopted regulations requiring certain natural gas and oil exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans.
The scope of federal jurisdictional reach over WOTUS has been subject to substantial revision in recent years. In 2015, the EPA and the U.S. Army Corps of Engineers (“Corps”) issued a rule defining the scope of the EPA’s and the Corps’ jurisdiction over WOTUS, which never took effect before being replaced by the Navigable Waters Protection Rule (“NWPR”) in 2020. A coalition of states and cities, environmental groups, and agricultural groups challenged the NWPR, which was vacated by a federal district court in August 2021. In January 2023, the EPA and the Corps issued a final rule that based the definition of WOTUS on the pre-2015 definition. Separately, in May 2023, the U.S. Supreme Court’s decision in Sackett v. EPA narrowed federal jurisdiction over wetlands to “traditional navigable waters” and wetlands or other waters that have a “continuous surface connection” with or are otherwise indistinguishable from traditional navigable water. In September 2023, the EPA and the Corps published a direct-to-final rule that conforms the regulatory definition of WOTUS to the Supreme Court’s May 2023 decision in Sackett. However, litigation opposing the September 2023 final rule remains ongoing and substantial uncertainty exists with respect to future implementation of the September 2023 rule and the scope of the CWA jurisdiction more generally. In addition, in an April 2020 decision defining the scope of the CWA that was issued days after the NWPR was published, the U.S. Supreme Court held that, in certain cases, discharges from a point source to a WOTUS through groundwater require a permit if the discharge is the “functional equivalent” of a direct discharge. The Court rejected the EPA and the Corps’ assertion that groundwater should be totally excluded from the CWA. In November 2023, the EPA issued draft guidance describing the functional equivalent analysis and the information that should be used to determine which discharges through groundwater may require a permit. If finalized, the guidance could subject previously unregulated discharges to CWA permit requirements. As a result, future implementation is uncertain at this time.
The Oil Pollution Act, as amended, or OPA, and regulations promulgated thereunder impose a variety of requirements on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills into WOTUS. A “responsible party” includes the owner or operator of an onshore facility, pipeline or vessel, or the lessee or permittee of the area in which an offshore facility is located. OPA assigns liability to each responsible party for oil cleanup costs and a variety of public and private damages. Although liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. Few defenses exist to the liability imposed by OPA. OPA imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. Oil accounted for 2% of our total production in 2023, 2% in 2022 and 3% in 2021.
We own or lease, and have in the past owned or leased, onshore properties that for many years have been used for or associated with the exploration for and production of natural gas and oil. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us and/or on or under other locations where such wastes have been taken for disposal. In addition, some of these properties have been operated by third parties whose treatment and disposal or release of wastes was not under our control. Under CERCLA, the CWA, RCRA and analogous state laws, we could be required to remove or remediate previously disposed wastes (including waste disposed of or released by prior owners or operators) or property contamination (including groundwater contamination by prior owners or operators), or to perform remedial plugging or closure operations to prevent future contamination.
Air Emissions. The Clean Air Act, as amended, restricts emissions into the atmosphere. Various activities we conduct as part of our operations, such as drilling, pumping and the use of vehicles, can result in emissions to the environment. We must obtain permits, typically from local authorities, to conduct various regulated activities. Federal and state governmental agencies are taking steps to regulate methane and other emissions from oil and natural gas activities, and further regulation could increase our costs or restrict our ability to produce. For example, in November 2021, the EPA issued a proposed rule under the Clean Air Act’s New Source Performance Standards (“NSPS”), known as Subpart OOOOa, which is intended to reduce methane emissions from new and existing oil and gas sources. The proposed rule would make the existing regulations in Subpart OOOOa more stringent and create a Subpart OOOOb to expand reduction requirements for new, modified, and reconstructed oil and gas sources, including standards focusing on certain source types that have never been regulated under the Clean Air Act (including intermittent vent pneumatic controllers, associated gas, and liquids unloading facilities). In addition, the proposed rule would establish “Emissions Guidelines,” creating a Subpart OOOOc that would require states to develop plans to reduce methane emissions from existing sources that must be at least as effective as presumptive standards set by the EPA. In November 2022, the EPA issued a proposed rule supplementing the November 2021 proposed rule. Among other things, the November 2022 supplemental proposed rule removes an emissions monitoring exemption for small wellhead-only sites and creates a new third-party monitoring program to flag large emissions events, referred to in the proposed rule as “super emitters”. In December 2023, the EPA announced a final rule, which among other things, requires the phase out of routine flaring of natural gas from newly constructed wells (with some exceptions) and routine leak monitoring at all well sites and compressor stations. Notably, the EPA updated the applicability date for Subparts OOOOb and OOOOc to December 6, 2022, meaning that sources constructed prior to that date will be considered existing sources with later compliance deadlines under the state plans. The final rule gives states, along with federal tribes that wish to regulate existing sources, two years to develop and submit their plans for reducing methane emissions from existing sources. The final emissions guidelines under Subpart OOOOc provide three years from the plan submission deadline for existing sources to comply. In addition, we are required to report emissions of various greenhouse gases, including methane. In addition, in August 2022, the current administration signed into law the Inflation Reduction Act of 2022. Among other things, the Inflation Reduction Act amends the Clean Air Act to include a Methane Emissions and Waste Reduction Incentive Program for petroleum and natural gas systems. This program requires the EPA to impose a “waste emissions charge” on certain oil and gas sources that are already required to report under the EPA’s Greenhouse Gas Reporting Program. In order to implement the program, the Inflation Reduction Act required revisions to greenhouse gas reporting regulations for petroleum and natural gas systems (Subpart W) by 2024. In July 2023, the EPA proposed to expand the scope of the Greenhouse Gas Reporting Program for petroleum and natural gas facilities, as required by the Inflation Reduction Act. Among other things, the proposed rule would expand the emissions events that are subject to reporting requirements to include “other large release events” and apply reporting requirements to certain new sources and sectors. The rule is expected to be finalized in the spring of 2024 and become effective on January 1, 2025, in advance of the deadline for greenhouse gas reporting for 2024 (March 2025). In January 2024, the EPA proposed a rule implementing the Inflation Reduction Act’s methane emissions charge. The proposed rule includes potential methodologies for calculating the amount by which a facility’s reported methane emissions are below or exceed the waste emissions thresholds and contemplates approaches for implementing certain exemptions created by the Inflation Reduction Act. The methane emissions charge imposed under the Methane Emissions and Waste Reduction Incentive Program for 2024 would be $900 per ton emitted over annual methane emissions thresholds, and would increase to $1,200 in 2025, and $1,500 in 2026. The emissions fee and funding provisions of the law could increase operating costs within the oil and gas industry and accelerate the transition away from fossil fuels, which could in turn adversely affect our business and results of operations.
Threatened and Endangered Species. The Endangered Species Act and comparable state laws protect species threatened with possible extinction. Similar protections are afforded to migratory birds under the Migratory Bird Treaty Act (“MBTA”). Protection of threatened and endangered species may have the effect of prohibiting or delaying us from obtaining drilling and other permits and may include restrictions on road building and other activities in areas containing the affected species or their habitats. Based on the species that have been identified and listed to date, we do not believe there are any species protected under the Endangered Species Act that would materially and adversely affect our operations at this time. To the extent species that are listed under the Endangered Species Act or similar state laws, or are protected under the MBTA, live in the areas where we operate, our ability to conduct or expand operations could be limited, or we could be forced to incur material additional costs. Moreover, our drilling activities may be delayed, restricted or precluded in protected habitat areas or during certain seasons, such as breeding and nesting seasons. The designation of previously unidentified endangered or threatened species could cause our operations to become subject to operating restrictions or bans, and limit future development activity in affected areas. In addition, the U.S. Fish and Wildlife Service and similar state agencies may designate critical or suitable habitat areas that they believe are necessary for the survival of threatened or endangered species. Such a designation could materially restrict use of or access to federal, state and private lands, which may reduce the profitability of our interests to the extent they are associated with such designations. There is also increasing interest in natural resource-related matters beyond protected species, such as general biodiversity, which may similarly require us or our customers to incur costs or take other measures which may adversely impact our business or operations.
Hydraulic Fracturing. We utilize hydraulic fracturing in drilling wells as a means of maximizing their productivity. It is an essential and common practice in the oil and gas industry used to stimulate the production of oil, natural gas, and associated liquids from dense and deep rock formations. Hydraulic fracturing involves using water, sand, and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow the flow of hydrocarbons into the wellbore.
In the past several years, there has been an increased focus on the environmental aspects of hydraulic fracturing, both in the United States and abroad. In the United States, hydraulic fracturing is typically regulated by state oil and natural gas commissions, but federal agencies have started to assert regulatory authority over certain aspects of the process. In addition to the EPA’s Subpart OOOO regulations discussed above, the EPA finalized pretreatment standards that prohibit the indirect discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned treatment works. Based on our current operations and practices, management believes such rules will not have a material adverse impact on our financial position, results of operations or cash flows, but these matters are subject to inherent uncertainties and management’s view may change in the future.
In addition, there are certain governmental reviews either underway or proposed that focus on environmental aspects of hydraulic fracturing practices. A number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. For example, the EPA released a report regarding 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 such as water withdrawals for fracturing in times or areas of low water availability, surface spills during the management of fracturing fluids, chemicals or produced water, injection of fracturing fluids into wells with inadequate mechanical integrity, injection of fracturing fluids directly into groundwater resources, discharge of inadequately treated fracturing wastewater to surface waters and disposal or storage of fracturing wastewater in unlined pits. The results of these studies could lead federal and state governments and agencies to develop and implement additional regulations.
Some states in which we operate have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure, waste disposal and well construction requirements on hydraulic fracturing operations or otherwise seek to ban fracturing activities altogether. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. In the event state, local, or municipal legal restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct, operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling and/or completion of wells.
Increased regulation and attention given to the hydraulic fracturing process has led to greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil, natural gas, and associated liquids including from the development of shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of additional federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells and increased compliance costs and time, which could adversely affect our financial position, results of operations and cash flows. In addition, various officials and candidates at the federal, state and local levels, including past presidential candidates, have proposed banning hydraulic fracturing altogether. We refer you to the risk factor “We, our service providers and our customers are subject to complex federal, state and local laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities” in Item 1A of Part I of this Annual Report. In addition, concerns have been raised about the potential for seismic activity to occur from the use of underground injection control wells, a predominant method for disposing of waste water from oil and gas activities. New rules and regulations may be developed to address these concerns, possibly limiting or eliminating the ability to use disposal wells in certain locations and increasing the cost of disposal in others. We utilize third parties to dispose of waste water associated with our operations. These third parties may operate injection wells and may be subject to regulatory restrictions relating to seismicity, which could result in increased costs for their services to dispose of waste water from our operations.
Greenhouse Gas Emissions and Climate Change. In response to findings regarding the potential impact of emissions of carbon dioxide, methane and other greenhouse gases on human health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, establish Prevention of Significant Deterioration, or PSD, construction and Title V operating permit reviews for certain large stationary sources. The Company’s operations are not currently impacted by said regulations. Facilities required to obtain PSD permits for their greenhouse gas emissions also will be required to meet “best available control technology” standards that will be established on a case-by case basis. In addition,
the EPA adopted rules requiring the monitoring and reporting of greenhouse gas emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which includes certain of our operations. The EPA also finalized rules in December 2023 intended to reduce methane emissions from new and existing oil and gas sources (discussed above). EPA rulemakings related to greenhouse gas emissions could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources.
In recent years, the U.S. Congress has considered legislation to reduce emissions of greenhouse gases, including methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas. It presently appears unlikely that comprehensive climate legislation will be passed by either house of Congress in the near future, although energy legislation and other regulatory initiatives have been proposed that are relevant to greenhouse gas emissions issues. For example, the Inflation Reduction Act of 2022, which appropriates significant federal funding for renewable energy initiatives and, for the first time ever, imposes a fee on greenhouse gas emissions from certain oil and gas facilities, was signed into law in August 2022 (discussed above). The emissions fee and funding provisions of the law could increase operating costs within the oil and gas industry and accelerate the transitions away from fossil fuels, which could in turn adversely affect our business and results of operations. Moreover, the current administration has highlighted addressing climate change as a priority and has issued several Executive Orders addressing climate change. In addition, a number of states, including states in which we operate, have enacted or passed measures to track and reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and regional greenhouse gas cap-and-trade programs. Most of these cap-and-trade programs require major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall greenhouse gas emission reduction goal is achieved. These reductions may cause the cost of allowances to escalate significantly over time.
Additionally, in March 2022, the SEC issued a proposed rule regarding the enhancement and standardization of mandatory climate-related disclosures for investors. The proposed rule would require registrants to include certain climate-related disclosures in their registration statements and periodic reports, including, but not limited to, information about the registrant’s governance of climate-related risks and relevant risk management processes; climate-related risks that are reasonably likely to have a material impact on the registrant’s business, results of operations, or financial condition and their actual and likely climate-related impacts on the registrant’s business strategy, model, and outlook; climate-related targets, goals and transition plan (if any); certain climate-related financial statement metrics in a note to their audited financial statements; Scope 1 and Scope 2 GHG emissions; and Scope 3 GHG emissions and intensity, if material, or if the registrant has set a GHG emissions reduction target, goal or plan that includes Scope 3 GHG emissions. Although the proposed rule’s ultimate date of effectiveness and the final form and substance of these requirements is not yet known and the ultimate scope and impact on our business is uncertain, compliance with the proposed rule, if finalized, may result in increased legal, accounting and financial compliance costs, make some activities more difficult, time-consuming and costly, and place strain on our personnel, systems and resources.
The adoption and implementation of regulations that require reporting of greenhouse gases or other climate-related information, or otherwise limit emissions of greenhouse gases from our equipment and operations could require us to incur increased operating costs, including costs to monitor and report on greenhouse gas emissions, install new equipment to reduce emissions of greenhouse gases associated with our operations, acquire emissions allowances or comply with new regulatory requirements. In addition, these regulatory initiatives could drive down demand for our products, stimulating demand for alternative forms of energy that do not rely on combustion of fossil fuels that serve as a major source of greenhouse gas emissions, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. While some new laws and regulations are prompting power producers to shift from coal to natural gas, which has a positive effect on demand, regulatory incentives or requirements to conserve energy, use alternative sources or reduce greenhouse gas emissions in product supply chains could reduce demand for the products we produce.
In December 2015, over 190 countries, including the United States, reached an agreement to reduce global greenhouse gas emissions (the “Paris Agreement”). The Paris Agreement entered into effect in November 2016 after more than 70 nations, including the United States, ratified or otherwise indicated their intent to be bound by the agreement. In 2021, the United States re-joined the Paris Agreement, and publicly announced that it was setting an economy-wide target of reducing U.S. greenhouse gas emissions by 50-52 percent below 2005 levels by 2030. The United States also announced the Global Methane Pledge, a pact that aims to reduce global methane emissions at least 30% below 2020 levels by 2030, including “all feasible reductions” in the energy sector. Since its formal launch at the United Nations 26th Conference of Parties, over 150 countries have joined the pledge. Furthermore, many state and local leaders have intensified or stated their intent to intensify efforts to support the international climate commitments. At the 27th Conference of Parties, the current administration announced the EPA’s supplemental proposed rule to reduce methane emissions from existing oil and gas sources, and agreed, in conjunction with the European Union and a number of other partner countries, to develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity natural gas. At the 28th Conference of Parties, member countries entered into an agreement that calls for actions toward achieving, at a global scale, a tripling of renewable energy capacity and doubling energy
efficiency improvements by 2030. The goals of the agreement, among other things, are to accelerate efforts toward the phase-down of unabated coal power, phase out inefficient fossil fuel subsidies, and take other measures that drive the transition away from fossil fuels in energy systems. Various state and local governments have also publicly committed to furthering the goals of the Paris Agreement. To the extent that governmental entities in the United States or other countries implement or impose climate change regulations on the oil and gas industry, it could have an adverse effect on our business.
The Company is committed to responsible energy development, and we recognize stakeholder concerns about climate change. We also understand that regulations and practices aimed at protecting the environment, and specifically reducing greenhouse gas emissions, can affect our business. We consider addressing these issues as part of our risk management process. We have published an updated climate change scenario analysis as a part of our 2023 Corporate Responsibility Report (which covers the year 2022 and is not incorporated by reference into this filing). This report and our corporate responsibility reporting is informed by recommendations from the Task Force on Climate-Related Financial Disclosures framework.
Employee Health and Safety. Our operations are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendments and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens.
Canada. Our activities in Canada have, to date, been limited to certain geological and geophysical activities and now are subject to a moratorium. If and when the moratorium ends and should we begin drilling and development activities in New Brunswick, we will be subject to Canadian federal, provincial and local environmental regulations.
Human Capital
We aim to provide a safe, healthy, respectful and fair workplace for all employees. We focus our actions to ensure our people are engaged and have the tools and skills to work safely and to be successful. Human capital management is primarily overseen by the Compensation Committee’s area of risk oversight. Further, the Board’s Health, Safety, Environmental & Corporate Responsibility Committee is tasked with overseeing and discussing workforce safety and community concerns and assessing related risks.
Workplace Culture/Respect, Diversity, and Inclusion. Southwestern is committed to respect in the workplace. We believe that sound, collaborative and respectful relationships among Company employees are essential to achieving and maintaining a high level of productivity and ethical business conduct. All employees are required to participate in a program addressing workplace behavior and respect on an annual basis. We recognize that every person should be treated fairly, and that every employment-related decision should be based on merits and qualifications for a particular job, including capability, performance and reflection of our corporate mission and values. Our policy requires that all decisions regarding recruiting, hiring, training, evaluation, assignment, advancement and termination of employment are made without unlawful discrimination on the basis of race, color, national origin, ancestry, citizenship, sex, sexual orientation, gender identity or expression, religion, age, pregnancy, disability, present military status or veteran status, genetic information, marital status or any other factor that the law protects from employment discrimination. We also seek to support workplace respect, diversity and inclusion through actively recruiting with key diversity organizations, working to build a diverse and local talent pool by encouraging diversity in science, technology, engineering and math education. We rolled out our Diversity and Inclusiveness training during 2022. From 2022 through 2023, over 93% of our employees, including officers and executive management, attended Diversity and Inclusiveness training. We intend to continue to support and expand diversity initiatives within our organization.
Our Human Rights Policy, which is consistent with the International Labour Organization’s Declaration on Fundamental Principles and Rights at Work, underscores our commitment to our workforce and extends to vendors and contractors.
Employee Engagement. Our human capital management objectives include identifying, recruiting, training, retaining, incentivizing and integrating our existing and additional employees. Our employee development programs aim to provide Company employees with the right tools, training and resources to be successful. We offer a range of development solutions targeted at meeting individual employees’ needs, including technical and non-technical training programs. We also measure employee engagement and enablement through a bi-annual survey, which is administered by a third-party vendor, and then work to create and implement an action plan based on feedback from the survey.
We aim to offer and maintain market competitive compensation and benefit programs for all of our employees in order to attract and retain superior and diverse talent. Compensation is based on several primary factors, including performance, skills, years of experience, time in position and market data.
Employee Health and Safety. We are focused on minimizing the risk of workplace incidents and preparing for emergencies, and strive to comply with all applicable occupational health and safety laws and regulations. Our leaders, including senior management, are evaluated in part on and held accountable for the HSE performance of their teams. HSE considerations are important factors in our business decisions, and we work to foster a true “ONE Team” culture, where our employees and contractors work together to uphold the same high safety standards. Our safety management approach is also articulated for all employees and contractors in our HSE Handbook, and we require employee training on the handbook and signed acknowledgment of the understanding of an agreement to follow handbook content. We provide a wide range of HSE training to fortify our safety culture, including hands-on Safety Leadership Training and our Training Assurance Program, which is a required HSE training program for all our contractors and employees working in the field. We use a robust incident management system database to track, analyze, report and follow up on HSE incidents. The goal of our incident management program is to identify trends and hazards to avoid incidents before they happen. We aim to analyze recordable incidents by type so that we can determine the most common incident types and develop targeted training.
As of December 31, 2023, we had 1,165 total employees, a 4% increase compared to year-end 2022. None of our employees were covered by a collective bargaining agreement at year-end 2023. We believe that our relationships with our employees are good.
Seasonality
Weather conditions and seasonality affect the demand for and prices of natural gas, oil and NGLs. Due to these fluctuations, results of operations for quarterly interim periods may not be indicative of the results realized on an annual basis.
Address, Internet Website and Availability of Public Filings
Our principal executive offices are located at 10000 Energy Drive, Spring, Texas 77389, and our telephone number is (832) 796-1000. We also maintain offices in Tunkhannock, Pennsylvania; Morgantown, West Virginia; Zanesville, Ohio; Frierson, Louisiana; Coushatta, Louisiana and Gloster, Louisiana. Our website is located at www.swn.com.
We furnish or file our Annual Reports on Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K and amendments to such reports and other documents with the SEC under the Exchange Act. The SEC also maintains an internet website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers, including us, that file electronically with the SEC. We also make these documents available free of charge at www.swn.com under the “Investors” link as soon as reasonably practicable after they are filed or furnished with the SEC.
Information on our website is not incorporated into this Annual Report on Form 10-K or our other filings with the SEC and is not a part of them.
Executive Officers of the Registrant
The following table shows certain information as of February 20, 2024 about our executive officers, as defined in Rule 3b-7 of the Exchange Act:
| | | | | | | | | | | | | | |
| Name | | Age | | Officer Position |
| William J. Way | | 64 | | President and Chief Executive Officer |
| Carl F. Giesler, Jr. | | 52 | | Executive Vice President and Chief Financial Officer |
| Clayton A. Carrell | | 58 | | Executive Vice President and Chief Operating Officer |
| Derek W. Cutright | | 46 | | Senior Vice President – Division Head |
| John P. Kelly | | 53 | | Senior Vice President – Division Head |
| Andy Huggins | | 43 | | Senior Vice President – Division Head |
| Quentin Dyson | | 54 | | Senior Vice President – Operations Services |
| Chris Lacy | | 46 | | Senior Vice President – General Counsel and Secretary |
| Carina Gillenwater | | 48 | | Senior Vice President – Chief Human Resources Officer |
| Dennis Price | | 59 | | Senior Vice President – Marketing, Transportation and Commercial |
Mr. Way was appointed Chief Executive Officer in January 2016. Prior to that, he served as Chief Operating Officer since 2011, having also been appointed President in December 2014. Prior to joining the Company, he was Senior Vice President, Americas of BG Group plc with responsibility for E&P, Midstream and LNG operations in the United States, Trinidad and Tobago, Chile, Bolivia, Canada and Argentina since 2007.
Mr. Giesler was appointed Executive Vice President and Chief Financial Officer in July 2021. Prior to that, he served as President and Chief Executive Officer and as a Director of SandRidge Energy, Inc., having been appointed to that position in
April 2020. Prior to that, he served as President and Chief Executive Officer and as a Director of Jones Energy, Inc., beginning in 2018. Prior to that, he served as President and Chief Executive Officer and as a Director of Miller Energy Resources, Inc., beginning in 2014.
Mr. Carrell was appointed Executive Vice President and Chief Operating Officer in December 2017. Prior to joining the Company, he was Executive Vice President and Chief Operating Officer of EP Energy since 2012.
Mr. Cutright was appointed Senior Vice President – Division Head in September 2019; he served as Vice President & General Manager of Southwest Appalachia since 2016. Prior to that, he served in various operational leadership roles since joining the Company in December 2008.
Mr. Kelly was appointed Senior Vice President – Division Head in October 2018, having previously served as Senior Vice President – Fayetteville since in 2017. Prior to joining the Company, he was President and Chief Executive Officer of Cantera Energy since 2012.
Mr. Huggins was appointed Senior Vice President – Division Head in September 2021, having previously served as Vice President of Commercial and Business Development since March 2018. Prior to that he served in various operational and technical leadership roles since joining the Company in 2007.
Mr. Dyson was appointed Senior Vice President of Operations Services in April 2019. He held Vice President roles at EP Energy and BP before joining SWN in January 2018 as Vice President – Operations Services.
Mr. Lacy was appointed Senior Vice President – General Counsel and Secretary in October 2023 having previously served as Vice President – General Counsel and Secretary since 2020. Prior to that he served in other various roles of increasing responsibility in the legal department since joining the Company in 2014.
Mrs. Gillenwater was appointed Senior Vice President – Chief Human Resources Officer in October 2023 having previously served as Vice President – Human Resources since joining the Company in June 2018. Prior to joining the Company, she served as Global Vice President of Human Resources at Nabors Industries and Vice President of Human Resources at Smith International / Schlumberger Ltd.
Mr. Price was appointed Senior Vice President – Marketing, Transportation and Commercial in May 2023 having previously served as Vice President, Marketing and Trading for EP Energy prior to joining the Company. Prior to that he served in various leadership roles at El Paso.
There are no family relationships between any of the Company’s directors or executive officers.
ITEM 1A. RISK FACTORS
You should carefully consider the following risk factors in addition to the other information included in this Annual Report. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in our common stock.
Risks Related to Our Business
Natural gas, oil and NGL prices and basis differentials greatly affect our revenues and thus profits, liquidity, growth, ability to repay our debt and the value of our assets.
Our revenues, profitability, liquidity, growth, ability to repay our debt and the value of our assets greatly depend on prices for natural gas, oil and NGLs. The markets for these commodities are volatile, and we expect that volatility to continue. The prices of natural gas, oil and NGLs fluctuate in response to changes in supply and demand (global, regional and local), transportation costs, market uncertainty and other factors that are beyond our control. Short- and long-term prices are subject to a myriad of factors such as:
•overall demand, including the relative cost of competing sources of energy or fuel;
•overall supply, including costs of production;
•the availability, proximity and capacity of pipelines, other transportation facilities and gathering, processing and storage facilities;
•regional basis differentials;
•national and worldwide economic and political conditions;
•weather conditions and seasonal trends;
•government regulations, such as regulation of natural gas transportation and price controls;
•inventory levels; and
•market perceptions of future prices, whether due to the foregoing factors or others.
For example, in 2023 and 2022, the NYMEX settlement price for natural gas ranged from a low of $1.99 per MMBtu in April 2023 to a high of $9.35 per MMBtu in September 2022, and during these periods our production was 86% and 88% natural gas, respectively. Although we hedge a large portion of our production against changing prices, derivatives do not protect all our future volumes, may result in our forgoing profit opportunities if markets rise and, for NGLs, are not always available for substantial periods into the future. In 2023, we received $345 million, net of amounts we paid, in settlement of hedging arrangements due to decreased commodity pricing.
Lower natural gas, oil and NGL prices directly reduce our revenues and thus our operating income and cash flow. Lower prices also reduce the projected profitability of further drilling and therefore are likely to reduce our drilling activity, which in turn means we will have fewer wells on production in the future. Lower prices also reduce the value of our assets, both by a direct reduction in what the production would be worth and by making some properties uneconomic, resulting in non-cash impairments to the recorded value of our reserves and non-cash charges to earnings. For example, in 2023, we reported non-cash impairment charges on our natural gas and oil properties totaling $1,710 million, primarily resulting from decreases in trailing 12-month average first-day-of-the-month natural gas prices throughout 2023, as compared to 2022. Given the decline in commodity prices during 2023 and early 2024, the Company expects that an additional non-cash impairment of its assets will likely occur in the first quarter of 2024 and perhaps later.
As of December 31, 2023, we had less than $4.0 billion of debt outstanding, consisting principally of senior notes maturing in various increments from 2025 to 2032 and $220 million of borrowings under our 2022 credit facility (defined below), which matures in 2027. At current commodity price levels, our net cash flow from operations is substantially higher than our interest obligations under this debt, but significant drops in realized prices could affect our ability to pay our current obligations or refinance our debt as it becomes due.
Moreover, general industry conditions may make it difficult or costly to refinance increments of this debt as it matures. Although our indentures do not contain significant covenants restricting our operations and other activities, our bank credit agreements contain financial covenants with which we must comply. We refer you to the risk factor “Our current and future levels of indebtedness may adversely affect our results and limit our growth.” Our inability to pay our current obligations or refinance our debt as it becomes due could have a material and adverse effect on our company. A sustained drop in commodity
prices, such as was generally experienced from 2014 to 2020, could reduce our revenues, profits and cash flow, cause us to record significant non-cash asset impairments and lead us to reduce both our level of capital investing and our workforce.
Significant capital investment is required to develop and replace our reserves and conduct our business.
Our activities require substantial capital investment, not only to expand revenues but also because production from existing wells and thus revenues decline each year. We intend to fund our future capital investing through net cash flows from operations, net of changes in working capital. Our ability to generate operating cash flow is subject to many of the risks and uncertainties that exist in our industry, some of which we may not be able to anticipate at this time. Future cash flows from operations are subject to a number of risks and variables, such as the level of production from existing wells, prices of natural gas, oil and NGLs, our success in developing and producing new reserves and the other risk factors discussed herein. If we are unable to fund capital investing, we could experience a further reduction in drilling new wells, acquiring new acreage and a loss of existing leased acreage, resulting in a decline in our cash flow from operations and natural gas, oil and NGL production and reserves.
If we are not able to develop and replace reserves, our production levels and thus our revenues and profits may decline.
Production levels from existing wells decline over time, and drilling new wells requires an inventory of leases and other rights with reserves that have not yet been drilled. Our future success depends largely upon our ability to find, develop or acquire additional natural gas, oil and NGL reserves that are economically recoverable. Unless we replace the reserves we produce through successful development, acquisition or exploration activities, our proved reserves and production will decline over time. Identifying and exploiting new reserves requires significant capital investment and successful drilling operations. Thus, our future natural gas, oil and NGL reserves and production, and therefore our revenues and profits, are highly dependent on our level of capital investments, our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves.
Our business depends on access to natural gas, oil and NGL gathering, processing and transportation systems and facilities. Changes to access and cost of these systems and facilities could adversely impact our business and financial condition. Our commitments to assure availability of transportation could lead to substantial payments for capacity we do not use if production falls below projected levels.
The marketability of our natural gas, oil and NGL production depends in large part on the operation, availability, proximity, capacity and expansion of transportation systems and facilities owned by third parties. For example, we can provide no assurance that sufficient transportation capacity will exist for expected production from Appalachia or Haynesville, or that we will be able to obtain sufficient transportation capacity on economic terms. During the past few years, several planned pipelines intended to service production in the Northeast United States have experienced delays in their in-service dates due to regulatory delays and litigation.
Producers compete by lowering their sales prices, resulting in the locational differences from NYMEX pricing. Further, a lack of available capacity on transportation systems and facilities or delays in their planned expansions could result in the shut-in of producing wells or the delay or discontinuance of drilling plans for properties. A lack of availability of these systems and facilities for an extended period of time could negatively affect our revenues. In addition, we have entered into contracts for firm transportation and any failure to renew those contracts on the same or better commercial terms could increase our costs and our exposure to the risks described above.
We have entered into gathering agreements in producing areas and multiple long-term firm transportation agreements relating to natural gas volumes from all our producing areas. As of December 31, 2023, our aggregate demand charge commitments under these firm transportation agreements and gathering agreements were approximately $9.3 billion. If our development programs fail to produce sufficient quantities of natural gas and ethane to fill the contracted capacity within expected timeframes, we would be required to pay demand or other charges for transportation on pipelines and gathering systems for capacity that we would not be fully utilizing. In those situations, which have occurred on a small scale at various times, we endeavor to sell or transfer that capacity to others or fill the excess capacity with production purchased from third parties. There can be no assurance that these measures will recoup the full cost of the unused transportation.
Strategic determinations, including the allocation of capital and other resources to strategic opportunities, are challenging in the face of shifting market conditions, and our failure to appropriately allocate capital and resources among our strategic opportunities may adversely affect our financial condition and reduce our future growth rate.
We necessarily must consider future price and cost environments when deciding how much capital we are likely to have available from net cash flow and how best to allocate it. Our current philosophy is to generally operate within cash flow from operations, net of changes in working capital, and to invest capital in a portfolio of projects that are projected to generate the
highest combined Internal Rate of Return. Volatility in prices and potential errors in estimating costs, reserves or timing of production of the reserves can result in uneconomic projects or economic projects generating less than anticipated returns.
Certain of our undeveloped assets are subject to leases that will expire over the next several years unless production is established on units containing the acreage.
Approximately 30,755 and 3,032 net acres of our Appalachia and Haynesville acreage, respectively, will expire in the next three years if we do not drill successful wells to develop the acreage or otherwise take action to extend the leases. Our ability to drill wells depends on a number of factors, including certain factors that are beyond our control, such as the ability to obtain permits on a timely basis or to compel landowners or lease holders on adjacent properties to cooperate. Further, we may not have sufficient capital to drill all the wells necessary to hold the acreage without increasing our debt levels, or given price projections at the time, drilling may not be projected to achieve a sufficient return or be judged to be the best use of our capital. To the extent we do not drill the wells, our rights to acreage can be lost.
Our proved natural gas, oil and NGL reserves are estimates that include uncertainties. Any material changes to these uncertainties or underlying assumptions could cause the quantities and net present value of our reserves to be overstated or understated.
As described in more detail under “Critical Accounting Policies and Estimates – Natural Gas and Oil Properties” in Item 7 of Part II of this Annual Report, our reserve data represents the estimates of our reservoir engineers made under the supervision of our management, and our reserve estimates are audited each year by Netherland, Sewell & Associates, Inc., or NSAI, an independent petroleum engineering firm. Reserve engineering is a subjective process of estimating underground accumulations of natural gas, oil and NGLs that cannot be measured in an exact manner. The process of estimating quantities of proved reserves is complex and inherently imprecise, and the reserve data included in this document are only estimates. The process relies on interpretations of available geologic, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as using historic natural gas, oil and NGL prices rather than future projections. Additional assumptions include drilling and operating expenses, capital investing, taxes and availability of funds. Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same data. 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, oil and NGLs 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, oil and NGL reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on the preceding 12-month average natural gas, oil and NGL 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 applicable accounting standards 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 oil and gas industry in general.
Natural gas and oil drilling and producing and transportation operations are complex and can be hazardous and may expose us to liabilities. Incidents related to HSE performance and our asset and operating integrity could adversely impact our business and financial condition.
Drilling and production operations are subject to many risks, including well blowouts, cratering and explosions, pipe failures, fires, formations with abnormal pressures, uncontrollable flows of oil, natural gas, brine or well fluids, severe weather, natural disasters, groundwater contamination and other environmental hazards and risks. Some of these risks or hazards could materially and adversely affect our revenues and expenses by reducing or shutting in production from wells, loss of equipment or otherwise negatively impacting the projected economic performance of our prospects. If any of these risks occurs, we could sustain substantial losses as a result of:
•injury or loss of life;
•severe damage to or destruction of property, natural resources or equipment;
•pollution or other environmental damage;
•clean-up responsibilities;
•regulatory investigations and administrative, civil and criminal penalties; and
•injunctions resulting in limitation or suspension of operations.
For our properties that we do not operate, we depend on the operator for operational and regulatory compliance.
We rely on third parties to transport our production to markets. Their operations, and thus our ability to reach markets, are subject to all of the risks and operational hazards inherent in transporting natural gas and ethane and natural gas compression, including:
•damages to pipelines, facilities and surrounding properties caused by third parties, severe weather, natural disasters, including hurricanes, and acts of terrorism;
•maintenance, repairs, mechanical or structural failures;
•damages to, loss of availability of and delays in gaining access to interconnecting third-party pipelines;
•disruption or failure of information technology systems and network infrastructure due to various causes, including unauthorized access or attack; and
•leaks of natural gas or ethane as a result of the malfunction of equipment or facilities.
A material event such as those described above could expose us to liabilities, monetary penalties or interruptions in our business operations. Although we may maintain insurance against some, but not all, of the risks described above, our insurance may not be adequate to cover casualty losses or liabilities, and our insurance does not cover penalties or fines that may be assessed by a governmental authority. Also, in the future we may not be able to obtain insurance at premium levels that justify its purchase.
We have made significant investments in oilfield service businesses, including our drilling rigs, water infrastructure and pressure pumping equipment, to lower costs and secure inputs for our operations and transportation for our production. If our development and production activities are curtailed or disrupted, we may not recover our investment in these activities, which could adversely impact our results of operations. In addition, our continued expansion of these operations may adversely impact our relationships with third-party providers.
We also have made investments to meet certain of our field services’ needs, including establishing our own drilling rig operation, water transportation system in Appalachia and pressure pumping capability. If our level of operations is reduced for a long period, we may not be able to recover these investments. Further, our presence in these service and supply sectors, including competing with them for qualified personnel and supplies, may have an adverse effect on our relationships with our existing third-party service and resource providers or our ability to secure these services and resources from other providers.
Our business depends on the availability of water and the ability to dispose of water. Limitations or restrictions on our ability to obtain or dispose of water may have an adverse effect on our financial condition, results of operations and cash flows.
Water is an essential component of drilling and hydraulic fracturing processes. Limitations or restrictions on our ability to secure sufficient amounts of water, which may be enhanced by changes in weather patterns, or to dispose of or recycle water after use, could adversely impact our operations. In some cases, water may need to be obtained from new sources and transported to drilling sites, resulting in increased costs. Moreover, the introduction of new environmental initiatives and regulations related to water acquisition or waste water disposal, including produced water, drilling fluids and other wastes associated with the exploration, development or production of hydrocarbons, could limit or prohibit our ability to utilize hydraulic fracturing or waste water injection control wells.
In addition, concerns have been raised about the potential for seismic activity to occur from the use of underground injection control wells, a predominant method for disposing of waste water from oil and gas activities. New rules and regulations may be developed to address these concerns, possibly limiting or eliminating the ability to use disposal wells in certain locations and increasing the cost of disposal in others. We utilize third parties to dispose of waste water associated with our operations. These third parties may operate injection wells and may be subject to regulatory restrictions relating to seismicity.
Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of water necessary for hydraulic fracturing of wells or the disposal of water may increase our operating costs or may cause us to delay, curtail or discontinue our exploration and development plans, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
A large portion of our producing properties remain concentrated in the Appalachian basin, making us vulnerable to risks associated with operating in limited geographic areas.
A large portion of our producing properties currently are geographically concentrated in the Appalachian basin in Pennsylvania, West Virginia and Ohio. At December 31, 2023, approximately 75% of our total estimated proved reserves were attributable to properties located in the Appalachian basin. As a result, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, state and local politics, processing or transportation capacity constraints, market limitations, availability of equipment and personnel, water shortages and other disruptions due to climate patterns, severe weather or interruption of the processing or transportation of natural gas, oil or NGLs.
Many of our business operations depend on activities performed by third parties. Changes to availability, costs and performance of personnel, products and services provided by third parties could adversely impact our business and financial condition.
We rely on third-party service providers to provide compression related services and to perform necessary drilling and completion, and other related operations. The ability of third-party service providers to perform such operations will depend on those service providers' ability to compete for, train, and retain qualified personnel as well as their financial condition, economic performance and ability to access capital, which in turn will depend upon the supply and demand for natural gas, oil and NGLs, prevailing economic conditions, and financial, business and other factors. These third-party service providers are also subject to various laws and regulations that could impose regulatory action that limits or suspends their ability to operate. The failure of a third-party service provider to adequately perform operations or comply with applicable laws and regulations could delay drilling or completion or reduce production from the property and adversely affect our financial condition and results of operations.
Changes to the ability of our customers to receive our products or meet their financial, performance and other obligations to us could adversely impact our business and financial condition.
In addition to credit risk related to receivables from commodity derivative contracts, our principal exposures to credit risk are through receivables resulting from the sale of our natural gas, oil and NGL production that we market to energy companies, end users and refineries ($553 million as of December 31, 2023). We are also subject to credit risk due to concentration of receivables with several significant customers. The largest purchaser of our products during the year ended December 31, 2023 accounted for approximately 14% of our product revenues. We do not require all of our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial condition.
Competition in the oil and natural gas industry is intense, making it more difficult for us to market natural gas, oil and NGLs, to secure trained personnel and appropriate services, to obtain additional properties and to raise capital.
Our cost of operations is highly dependent on third-party services, and competition for these services can be significant, especially in times when commodity prices are rising. Similarly, we compete for trained, qualified personnel, and in times of lower prices for the commodities we produce, we and other companies with similar production profiles may not be able to attract and retain this talent. Our ability to acquire and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing natural gas, oil and NGLs and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and gas industry. Certain of our competitors may possess and employ financial, technical and personnel resources greater than ours. Those companies may be able to pay more for personnel, property and services and to attract capital at lower rates. This may become more likely if prices for oil and NGLs increase faster than prices for natural gas, as natural gas comprises a greater percentage of our overall production than it does for most of the companies with whom we compete for talent.
We may be unable to dispose of assets on attractive terms, and may be required to retain liabilities for certain matters.
Various factors could materially affect our ability to dispose of assets if and when we decide to do so, including the availability of purchasers willing to purchase the assets at prices acceptable to us, particularly in times of reduced and volatile commodity prices. Sellers typically retain liabilities for certain matters. The magnitude of any such retained liability or indemnification obligation may be difficult to quantify at the time of the transaction and ultimately may be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release us from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after a sale, we may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations.
Changes to applicable U.S. tax laws and regulations could affect our business and future profitability.
The elimination of certain key U.S. federal income tax deductions currently available to oil and natural gas exploration and production companies may be proposed in the future. These changes may include, among other proposals:
•repeal of the percentage depletion allowance for natural gas and oil properties;
•elimination of current deductions for intangible drilling and development costs;
•elimination of the deduction for certain domestic production activities; and
•extension of the amortization period for certain geological and geophysical expenditures.
The passage of any such proposals, or any similar legislation, could have an adverse effect on our financial position, results of operations and cash flows.
Our ability to use our net operating loss carryforwards and certain other tax attributes will be limited.
At December 31, 2023, we had substantial amounts of net operating loss carryforwards (“NOLs”) and other attributes for U.S. federal and state income tax purposes. Due to the issuance of common stock in 2021 associated with the Indigo Merger, we incurred a cumulative ownership change under Sections 382 and 383 of the Internal Revenue Code (“Code”), and as such, our NOLs and other attributes prior to the acquisition are subject to an annual limitation under Section 382 of the Code of approximately $48 million. The ownership change and resulting annual limitation will result in the expiration of NOLs or other tax attributes otherwise available. At December 31, 2023, we had approximately $4 billion of federal NOLs, of which approximately $3 billion have an expiration date between 2035 and 2037 and $1 billion have an indefinite carryforward life. We currently estimate that approximately $2 billion of these federal NOLs will expire before they are able to be used. If a subsequent ownership change were to occur as a result of future transactions in our common stock, our use of remaining U.S. tax attributes may be further limited.
We may experience adverse or unforeseen tax consequences due to further developments affecting our deferred tax assets which could significantly affect our results of operations.
Deferred tax assets, including NOLs, represent future savings of taxes that would otherwise be paid in cash. As discussed above, at December 31, 2023, we had substantial amounts of NOLs for U.S. federal and state income tax purposes. Our ability to utilize our deferred tax assets is dependent on the amount of future pre-tax income that we are able to generate through our operations or sale of assets and the applicable U.S. federal income tax and state tax laws. If management concludes that it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized, a valuation allowance will be recognized in the period that this conclusion is reached.
A cyber incident could result in information theft, data corruption, operational disruption and/or financial loss.
Our business has become increasingly dependent on digital technologies to conduct day-to-day operations, including certain development, exploration and production activities as well as processing of revenues and payments. We depend on digital technology, including information systems and related infrastructure as well as cloud applications and services, to process and record financial and operating data, analyze seismic and drilling information, conduct reservoir modeling and reserves estimation, communicate with employees and business associates, perform compliance reporting and in many other activities related to our business. Our vendors, service providers, purchasers of our production and financial institutions are also dependent on digital technology.
As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, have also increased. Our technologies, systems, networks, and those of our business associates are the target of cyber-attacks, which could lead to disruptions in critical systems, unauthorized release of confidential or protected information, corruption of data or other disruptions of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period.
A cyber-attack involving our information systems and related infrastructure, or that of companies with which we deal, could disrupt our business and negatively impact our operations in a variety of ways, including:
•unauthorized access to seismic data, reserves information, strategic information or other sensitive or proprietary information could have a negative impact on our ability to compete for natural gas and oil resources;
•unauthorized access to personal identifying information of property lessors, working interest partners, employees and vendors, which could expose us to allegations that we did not sufficiently protect that information;
•data corruption or operational disruption of production infrastructure could result in loss of production, or accidental discharge;
•a cyber-attack on a vendor or service provider could result in supply chain disruptions, which could delay or halt our major development projects; and
•a cyber-attack on a third party gathering, pipeline or rail service provider could delay or prevent us from marketing our production, resulting in a loss of revenues.
These events could damage our reputation and lead to financial losses from remedial actions, loss of business or potential liability, which could have a material adverse effect on our financial condition, results of operations or cash flows.
To date we have not experienced any material losses or interruptions relating to cyber-attacks; however, there can be no assurance that we will not suffer such losses in the future. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities.
Terrorist activities could materially and adversely affect our business and results of operations.
Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign attacks, as well as military or other actions taken in response to these acts, could cause instability in the global financial and energy markets. Continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy in unpredictable ways, including the disruption of energy supplies and markets, increased volatility in commodity prices or the possibility that the infrastructure on which we rely could be a direct target or an indirect casualty of an act of terrorism, and, in turn, could materially and adversely affect our business and results of operations.
The physical impacts of adverse weather may have a negative impact on our business and results of operations.
The physical effects of adverse weather conditions, such as increased frequency and severity of droughts, storms, floods and other climatic events, could adversely affect or delay demand for our products or cause us to incur significant costs in preparing for, or responding to, the effects of climatic events themselves. Potential adverse effects could include disruption of our production activities, including, for example, damages to our facilities from winds or floods, increases in our costs of operation or reductions in the efficiency of our operations, reducing the availability of electrical power, road accessibility, and transportation facilities, impacts on our personnel, supply chain, distribution chain or customers, as well as potentially increased costs for insurance coverages in the aftermath of such effects. Energy demand could increase or decrease as a result of extreme weather conditions depending on the duration and magnitude of the climatic event. Increased energy demand due to weather changes may require us to invest in additional equipment to serve increased demand. A decrease in energy use due to weather changes may affect our financial condition through decreased revenues. Such impacts may be proportionately more severe given the geographical concentration of our operations. Any one of these factors has the potential to have a material adverse effect on our business, financial condition, results of operations, and cash flow. Our ability to mitigate the physical impacts of adverse weather conditions depends in part upon our disaster preparedness and response along with our business continuity planning.
Negative public perception regarding us and/or our industry and increasing scrutiny of ESG matters could have an adverse effect on our business, financial condition and results of operations and damage our reputation.
Negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about climate change, emissions, hydraulic fracturing, seismicity, oil spills and explosions of transmission lines, may lead to increased litigation risk and regulatory, legislative and judicial 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, various officials and candidates at the federal, state and local levels, including some presidential candidates, have proposed banning hydraulic fracturing altogether.
Further, increasing attention to climate change, societal expectations on companies to address climate change, investor and societal expectations regarding voluntary ESG disclosures, generally, and fuel conservation measures, alternative fuel requirements, and increasing consumer demand for alternative forms of energy or energy efficiency initiatives or products may result in increased costs, reduced demand for our products, reduced profits, and negative impacts on our stock price and access to capital markets.
Further, our operations, projects and growth opportunities require us to have strong relationships with various key stakeholders, including our shareholders, employees, suppliers, customers, local communities and others. We may face pressures from stakeholders, many of whom are increasingly focused on climate change, to prioritize sustainable energy practices, reduce our carbon footprint and promote sustainability while at the same time remaining a successfully operating public company. If we do not successfully manage expectations across these varied stakeholder interests, it could erode our stakeholder trust and thereby affect our brand and reputation. Such erosion of confidence could negatively impact our business through decreased demand and growth opportunities, delays in projects, increased legal action and regulatory oversight, adverse press coverage and other adverse public statements, difficulty hiring and retaining top talent, difficulty obtaining necessary approvals and permits from governments and regulatory agencies on a timely basis and on acceptable terms and difficulty securing investors and access to capital.
Moreover, while we create and publish voluntary disclosures regarding ESG matters from time to time, some of the statements in those voluntary disclosures may be based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many ESG matters. In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings could lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital. In addition, failure or a perception (whether or not valid) of failure to implement our ESG strategy or achieve sustainability goals and targets we have set, including emissions reduction targets, could damage our reputation, causing our investors or consumers to lose confidence in our Company and brands, and negatively impact our operations. Our continuing efforts to research, establish, accomplish and accurately report on the implementation of our ESG strategy, including any ESG goals, may also create additional operational risks and expenses and expose us to reputational, legal and other risks.
Developments related to climate change may have a material and adverse effect on us.
Governmental and regulatory bodies, investors, consumers, industry and other stakeholders have been increasingly focused on combatting the effects of climate change. This focus, together with changes in consumer and industrial/commercial behavior, preferences and attitudes with respect to the generation and consumption of energy, petroleum products and the use of products manufactured with, or powered by, petroleum products, may in the long-term result in (i) the enactment of climate change-related regulations, policies and initiatives (at the government, regulator, corporate and/or investor community levels), including alternative energy requirements, new fuel consumption standards, energy conservation and emissions reductions measures and responsible energy development, (ii) technological advances with respect to the generation, transmission, storage and consumption of energy (e.g., wind, solar and hydrogen power, smart grid technology and battery technology, increasing efficiency) and (iii) increased availability of, and increased consumer and industrial/commercial demand for, alternative energy sources and products manufactured with, or powered by, alternative energy sources (e.g., electric vehicles and renewable residential and commercial power supplies). These developments may in the future adversely affect the demand for products manufactured with, or powered by, petroleum products and the demand for, and in turn the prices of, the natural gas, crude oil, and NGLs that we sell. Such developments may also adversely impact, among other things, the availability to us of necessary third-party services and facilities that we rely on, which may increase our operational costs and adversely affect our ability to successfully carry out our business strategy. Climate change-related developments may impact the market prices of or our access to raw materials such as energy and water and therefore result in increased costs to our business. For further discussion regarding the impact of commodity prices (including fluctuations in commodity prices) on our financial condition, cash flows and results of operations, see the risk factor entitled “Natural gas, oil and NGL prices and basis differentials greatly affect our revenues and thus profits, liquidity, growth, ability to repay our debt and the value of our assets.”
Further, climate change-related developments may result in negative perceptions of the traditional oil and gas industry and, in turn, reputational risks, including perceptions regarding the sufficiency of our ESG program associated with exploration and production activities. Such negative perceptions and reputational risks may in the future adversely affect our ability to successfully carry out our business strategy, for example, by adversely affecting the availability and cost to us of capital. There have been efforts in recent years, for example, to influence the investment community, including investment advisors, insurance companies, and certain sovereign wealth, pension and endowment funds and other groups, by promoting divestment of fossil fuel equities and pressuring lenders to limit funding and insurance underwriters to limit coverages to companies engaged in the extraction of fossil fuel reserves. Financial institutions may elect in the future to shift some or all of their investment into non-fossil fuel related sectors. There is also a risk that financial institutions may be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. Certain investment banks and asset managers based both domestically and
internationally have announced that they are adopting climate change guidelines for their banking and investing activities. Institutional lenders who provide financing to energy companies have also become more attentive to sustainable lending practices, and some may elect not to provide traditional energy producers or companies that support such producers with funding. Ultimately, the foregoing factors could make it more difficult to secure funding for exploration and production activities or adversely impact the cost of capital for both us and our customers, and could thereby adversely affect the demand and price of our securities. Limitation of investments in and financings for energy companies could also result in the restriction, delay or cancellation of infrastructure projects and energy production activities.
In addition, the enactment of climate change-related regulations, policies and initiatives (at the government, corporate and/or investor community levels) may in the future result in increases in our compliance costs and other operating costs and have other adverse effects (e.g., greater potential for governmental investigations or litigation). For further discussion regarding the risks to us of climate change-related regulations, policies and initiatives, see the discussion below in the section entitled “Risks Related to Governmental Regulation”.
Furthermore, claims have been made against certain energy companies alleging that greenhouse gas emissions from oil and natural gas operations constitute a public nuisance under federal and/or state common law, or alleging that the companies have been aware of the adverse effects of climate change for some time but failed to adequately disclose such impacts to their investors or customers. As a result, private individuals or public entities may seek to enforce environmental laws and regulations against us and could allege personal injury, property damages or other liabilities. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.
Judicial decisions can affect our rights and obligations.
Our ability to develop natural gas, oil and NGLs depends on the leases and other mineral rights we acquire and the rights of owners of nearby properties. We operate in areas where judicial decisions have not yet definitively interpreted various contractual provisions or addressed relevant aspects of property rights, nuisance and other matters that could be the source of claims against us as a developer or operator of properties. Although we plan our activities according to our expectations of these unresolved areas, based on decisions on similar issues in these jurisdictions and decisions from courts in other states that have addressed them, courts could resolve issues in ways that increase our liabilities or otherwise restrict or add costs to our operations.
Common stockholders will be diluted if additional shares are issued.
We endeavor to create value for our stockholders on a per share basis. From time to time we have issued stock to raise capital for our business or as consideration for acquisitions. We also issue restricted stock, options and performance share units to our employees and directors as part of their compensation. In addition, we may issue additional shares of common stock, additional notes or other securities or debt convertible into common stock, to extend maturities or fund capital expenditures. If we issue additional shares of our common stock in the future, it may have a dilutive effect on our current outstanding stockholders.
Anti-takeover provisions in our organizational documents and under Delaware law may impede or discourage a takeover, which could cause the market price of our common stock to decline.
We are a Delaware corporation, and the anti-takeover provisions of Delaware law impose various impediments to the ability of a third party to acquire control of us, even if a change in control would be beneficial to our existing stockholders, which, under certain circumstances, could reduce the market price of our common stock. In addition, protective provisions in our Amended and Restated Certificate of Incorporation, as amended, and Second Amended and Restated Bylaws or the implementation by our Board of Directors of a stockholder rights plan that could deter a takeover.
Loss of our key executive officers or other personnel, or an inability to attract and retain such officers and personnel, could negatively affect our business.
Our future success depends on the skills, experience and efforts of our key executive officers. The sudden loss of any of these executives’ services or our failure to appropriately plan for any expected key executive succession could materially and adversely affect our business and prospects, as we may not be able to find suitable individuals to replace them on a timely basis, if at all. Additionally, we also depend on our ability to attract and retain qualified personnel to operate and expand our business. Workers may choose to pursue employment with our competitors or in other fields; this competition has become exacerbated by the increase in employee resignations currently taking place throughout the United States. If we fail to attract or retain talented new employees, our business and results of operations could be negatively affected.
A pandemic may negatively affect our business, operating results and financial condition.
As a result of a pandemic, we may experience in the future, among other things, a reduction in demand for natural gas, oil, NGLs and other products derived therefrom, and may experience in the future reduced availability of personnel, equipment and services critical to our ability to operate our properties, which could in the future adversely impact, our business, results of operations and overall financial performance.
Risks Related to our Indebtedness and Financing Abilities
A downgrade in our credit rating could negatively impact our cost of and ability to access capital and our liquidity.
Actual or anticipated changes or downgrades in our credit ratings, including any announcement that our ratings are under review for a downgrade, could impact our ability to access debt markets in the future to refinance existing debt or obtain additional funds, affect the market value of our senior notes and increase our borrowing costs. Such ratings are limited in scope, and do not address all material risks relating to us, but rather reflect only the view of each rating agency of the likelihood we will be able to repay our debt at the time the rating is issued. An explanation of the significance of each rating may be obtained from the applicable rating agency. As of February 20, 2024, our long-term issuer ratings were Ba1 by Moody’s, BB+ by Standard and Poor’s and BB+ by Fitch Investor Services. There can be no assurance that such credit ratings will remain in effect for any given period of time or that such ratings will not be lowered, suspended or withdrawn entirely by the rating agencies, if, in each rating agency’s judgment, circumstances so warrant.
Actual downgrades in our credit ratings may also impact our interest costs and liquidity. The interest rates under certain of our senior notes increases as credit ratings fall. Many of our existing commercial contracts contain, and future commercial contracts may contain, provisions permitting the counterparty to require increased security upon the occurrence of a downgrade in our credit rating. Providing additional security, such as posting letters of credit, could reduce our available cash or our liquidity under our 2022 credit facility for other purposes. We had no of letters of credit outstanding at December 31, 2023. The amount of additional financial assurance would depend on the severity of the downgrade from the credit rating agencies, and a downgrade could result in a decrease in our liquidity.
Our current and future levels of indebtedness may adversely affect our results and limit our growth.
At December 31, 2023, we had total indebtedness of less than $4.0 billion. The terms of the indentures governing our outstanding senior notes, our credit facilities, and the lease agreements relating to our drilling rigs, other equipment and headquarters building, which we collectively refer to as our “financing agreements,” impose restrictions on our ability and, in some cases, the ability of our subsidiaries to take a number of actions that we may otherwise desire to take, which may include, without limitation, one or more of the following:
•incurring additional debt;
•redeeming stock or redeeming certain debt;
•making certain investments;
•creating liens on our assets; and
•selling assets.
The revolving credit facility we entered into in April 2022, as amended (our “2022 credit facility”), contains customary representations, warranties and covenants including, among others, the following covenants:
•a prohibition against incurring debt, subject to permitted exceptions;
•a restriction on creating liens on assets, subject to permitted exceptions;
•restrictions on mergers and asset dispositions;
•restrictions on use of proceeds, investments, declaring dividends, repurchasing junior debt, transactions with affiliates, or change of principal business; and
•maintenance of the following financial covenants, commencing with the fiscal quarter ended March 31, 2022:
1.Minimum current ratio of no less than 1.00 to 1.00, whereby current ratio is defined as the Company’s consolidated current assets (including unused commitments under the credit agreement, but excluding non-cash derivative assets) to consolidated current liabilities (excluding non-cash derivative obligations and current maturities of long-term debt).
2.Maximum total net leverage ratio of not greater than, with respect to the prior four fiscal quarters ending on or after March 31, 2022, 4.00 to 1.00. Total net leverage ratio is defined as total debt less cash on hand (up to the lesser of 10% of credit limit or $150 million) divided by consolidated EBITDAX for the last four consecutive quarters. Consolidated EBITDAX, as defined in the credit agreement governing the Company’s 2022 credit facility, excludes the effects of interest expense, depreciation, depletion and amortization, income tax, any non-cash impacts from impairments, certain non-cash hedging activities, stock-based compensation expense, non-cash gains or losses on asset sales, unamortized issuance cost, unamortized debt discount and certain restructuring costs.
As of December 31, 2023, we were in compliance with all of the covenants of our 2022 credit facility. Our ability to comply with these financial covenants depends in part on the success of our development program and upon factors beyond our control, such as the market prices for natural gas, oil and NGLs.
Our level of indebtedness and off-balance sheet obligations, and the covenants contained in our financing agreements, could have important consequences for our operations, including:
•requiring us to dedicate a substantial portion of our cash flow from operations to required payments, thereby reducing the availability of cash flow for working capital, capital investing and other general business activities;
•limiting our ability to obtain additional financing in the future for working capital, capital investing, acquisitions and general corporate and other activities;
•limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and
•detracting from our ability to successfully withstand a downturn in our business or the economy generally.
Any significant reduction in the borrowing base under our 2022 credit facility may negatively impact our ability to fund our operations, and we may not have sufficient funds to repay borrowings under our 2022 credit facility if required as a result of a borrowing base redetermination.
The amount we may borrow under our 2022 credit facility is capped at the lower of the total of our bank commitments and a “borrowing base” determined from time to time by the lenders based on our reserves, market conditions and other factors. As of December 31, 2023, the borrowing base was reaffirmed at $3.5 billion in October 2023 and we had total aggregate elected commitments of $2.0 billion. The borrowing base is subject to scheduled semiannual and other elective collateral borrowing base redeterminations based on our natural gas, oil and NGL reserves and other factors. As of December 31, 2023, we had $220 million of outstanding borrowings under the 2022 credit facility, no of letters of credit issued and our unused borrowing capacity was approximately $1.8 billion which exceeds our currently modeled needs. Any significant reduction in our borrowing base as a result of borrowing base redeterminations or otherwise may negatively impact our liquidity and our ability to fund our operations and, as a result, may have a material adverse effect on our financial position, results of operation and cash flow. Further, if the outstanding borrowings under our 2022 credit facility were to exceed the lower of our elected commitments level and the borrowing base as a result of any such redetermination or other reasons, we would be required to repay the excess within a brief period. We may not have sufficient funds to make such repayments. If we do not have sufficient funds and we are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.
Our ability to comply with the covenants and other restrictions in our financing agreements may be affected by events beyond our control, including prevailing economic and financial conditions.
Failure to comply with the covenants and other restrictions could lead to an event of default and the acceleration of our obligations under our senior notes, credit facilities or other financing agreements, and in the case of the lease agreements for drilling rigs, compressors and pressure pumping equipment, loss of use of the equipment. In particular, the occurrence of risks identified elsewhere in this section, such as declines in commodity prices, increases in basis differentials and inability to access markets, could reduce our profits and thus the cash we have to fulfill our financial obligations. If we are unable to satisfy our obligations with cash on hand, we could attempt to refinance such debt, sell assets or repay such debt with the proceeds from an equity offering. We cannot assure that we will be able to generate sufficient cash flow to pay the interest on our debt, to meet our lease obligations, or that future borrowings, equity financings or proceeds from the sale of assets will be available to pay or refinance such debt or obligations. The terms of our financing agreements may also prohibit us from taking such actions. Factors that will affect our ability to raise cash through an offering of our capital stock, a refinancing of our debt or a sale of assets include financial market conditions and our market value and operating performance at the time of such offering or other financing. We cannot assure that any such proposed offering, refinancing or sale of assets can be successfully completed or, if completed, that the terms will be favorable to us.
Risks Related to Governmental Regulation
Climate change legislation or regulations governing the emissions of greenhouse gases could result in increased operating costs and reduce demand for the natural gas, oil and NGLs we produce, and concern in financial and investment markets over greenhouse gasses and fossil fuel production could adversely affect our access to capital and the price of our common stock.
In response to findings regarding the potential impact of emissions of carbon dioxide, methane and other greenhouse gases on human health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, establish Prevention of Significant Deterioration, or PSD, construction and Title V operating permit reviews for certain large stationary sources. Facilities required to obtain PSD permits for their greenhouse gas emissions also will be required to meet “best available control technology” standards that will be established on a case-by-case basis. EPA rulemakings related to greenhouse gas emissions could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources.
In November 2021, the EPA issued a proposed rule intended to reduce methane emissions from new and existing oil and gas sources. The proposed rule would make the existing regulations in Subpart OOOOa more stringent and create a Subpart OOOOb to expand reduction requirements for new, modified, and reconstructed oil and gas sources, including standards focusing on certain source types that have never been regulated under the Clean Air Act (including intermittent vent pneumatic controllers, associated gas, and liquids unloading facilities). In addition, the proposed rule would establish “Emissions Guidelines,” creating a Subpart OOOOc that would require states to develop plans to reduce methane emissions from existing sources that must be at least as effective as presumptive standards set by the EPA. In November 2022, the EPA issued a proposed rule supplementing the November 2021 proposed rule. Among other things, the November 2022 supplemental rule removes an emissions monitoring exemption for small wellhead-only sites and creates a new third-party monitoring program to flag large emissions events, referred to in the proposed rule as “super emitters”. In December 2023, the EPA announced a final rule, which, among other things, requires the phase out of routine flaring of natural gas from newly constructed wells (with some exceptions) and routine leak monitoring at all well sites and compressor stations. Notably, the EPA updated the applicability date for Subparts OOOOb and OOOOc to December 6, 2022, meaning that sources constructed prior to that date will be considered existing sources with later compliance deadlines under state plans. The final rule gives states, along with federal tribes that wish to regulate existing sources, two years to develop and submit their plans for reducing methane emissions from existing sources. The final emissions guidelines under Subpart OOOOc provide three years from the plan submission deadline for existing sources to comply. Although there may be an adverse financial impact (including compliance costs, potential permitting delays and increased regulatory requirements) associated with these regulatory changes, the extent and magnitude of impacts cannot be reliably or accurately estimated due to the present uncertainty regarding any additional measures and how they will be implemented.
In recent years, the U.S. Congress has considered legislation to reduce emissions of greenhouse gases, including methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas. It presently appears unlikely that comprehensive climate legislation will be passed by either house of Congress in the near future, although energy legislation and other regulatory initiatives have been proposed that are relevant to greenhouse gas emissions issues. For example, the Inflation Reduction Act of 2022, which appropriates significant funding for renewable energy initiatives and, for the first time ever, imposes a fee on greenhouse gas emissions from certain oil and gas facilities, was signed into law in August 2022. The Inflation Reduction Act amends the Clean Air Act to include a Methane Emissions and Waste Reduction Incentive Program, which requires the EPA to impose a “waste emissions charge” on certain natural gas and oil sources that are already required to report under EPA’s Greenhouse Gas Reporting Program. In order to implement the program, the Inflation Reduction Act required revisions to greenhouse gas reporting regulations for petroleum and natural gas systems (Subpart W) by 2024. In July 2023, the EPA proposed to expand the scope of the Greenhouse Gas Reporting Program for petroleum and natural gas facilities, as required by the Inflation Reduction Act. Among other things, the proposed rule would expand the emissions events that are subject to reporting requirements to include “other large release events” and apply reporting requirements to certain new sources and sectors. The rule is expected to be finalized in the spring of 2024 and become effective on January 1, 2025, in advance of the deadline for greenhouse gas reporting for 2024 (March 2025). In January 2024, the EPA proposed a rule implementing the Inflation Reduction Act’s methane emissions charge. The proposed rule includes potential methodologies for calculating the amount by which a facility’s reported methane emissions are below or exceed the waste emissions thresholds and contemplates approaches for implementing certain exemptions created by the Inflation Reduction Act. The methane emissions charge imposed under the Methane Emissions and Waste Reduction Incentive Program for 2024 would be $900 per ton emitted over annual methane emissions thresholds, and would increase to $1,200 in 2025, and $1,500 in 2026. The emissions fee and funding provisions of the law could increase operating costs within the oil and gas industry and accelerate the transition away from fossil fuels, which could in turn adversely affect our business and results of operations. Moreover, the current administration has highlighted addressing climate change as a priority and has issued several Executive Orders addressing climate change. In addition, a number of states, including states in which we operate, have enacted or passed measures to track and reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories, carbon taxes, policies
and incentives to encourage the use of renewable energy or alternative low-carbon fuels, and regional greenhouse gas cap-and-trade programs. Most of these cap-and-trade programs require major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall greenhouse gas emission reduction goal is achieved. These reductions may cause the cost of allowances to escalate significantly over time.
The adoption and implementation of regulations that require reporting of greenhouse gases or other climate-related information (such as the SEC’s “Proposed Rules to Enhance and Standardize Climate-Related Disclosures for Investors,” discussed below), or otherwise seek to limit emissions of greenhouse gases from our equipment and operations could require us to incur increased operating costs, including costs to monitor and report on greenhouse gas emissions, install new equipment to reduce emissions of greenhouse gases associated with our operations, acquire emissions allowances or comply with new regulatory requirements. In addition, these regulatory initiatives could drive down demand for our products, stimulating demand for alternative forms of energy that do not rely on combustion of fossil fuels that serve as a major source of greenhouse gas emissions, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. While some new laws and regulations are prompting power producers to shift from coal to natural gas, which has a positive effect on demand, regulatory incentives or requirements to conserve energy, use alternative sources or reduce greenhouse gas emissions in product supply chains could reduce demand for the products we produce.
Additionally, the SEC issued a proposed rule in March 2022 that would mandate extensive disclosure of climate-related data, risks, and opportunities, including financial impacts, physical and transition risks, related governance and strategy, and GHG emissions, for certain public companies. We cannot predict the costs of implementation or any potential adverse impacts resulting from the rulemaking. To the extent this rulemaking is finalized as proposed, we could incur increased costs relating to the assessment and disclosure of climate-related risks. We may also face increased litigation risks related to disclosures made pursuant to the rule if finalized as proposed. In addition, enhanced climate disclosure requirements could accelerate the trend of certain stakeholders and lenders restricting or seeking more stringent conditions with respect to their investments in certain carbon-intensive sectors.
In 2021, the United States rejoined the Paris Agreement and announced that it was setting an economy-wide target of reducing U.S. greenhouse gas emissions by 50-52 percent below 2005 levels by 2030. The United States also publicly announced the Global Methane Pledge, a pact that aims to reduce global methane emissions at least 30% below 2020 levels by 2030. Since its formal launch at the United Nations 26th Conference of Parties, over 150 countries have joined the pledge. Furthermore, many state and local leaders have intensified or stated their intent to intensify efforts to support the international climate commitments. At the 27th Conference of Parties, the current administration announced the EPA’s supplemental proposed rule to reduce methane emissions from existing oil and gas sources, and agreed, in conjunction with the European Union and a number of other partner countries, to develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity natural gas. At the 28th Conference of Parties, member countries entered into an agreement that calls for actions toward achieving, at a global scale, a tripling of renewable energy capacity and doubling energy efficiency improvements by 2030. The goals of the agreement, among other things, are to accelerate efforts toward the phase-down of unabated coal power, phase out inefficient fossil fuel subsidies, and take other measures that drive the transition away from fossil fuels in energy systems. Various state and local governments have also publicly committed to furthering the goals of the Paris Agreement. To the extent that governmental entities in the United States or other countries implement or impose climate change regulations on the oil and natural gas industry, or that investors insist on compliance regardless of legal requirements, it could have an adverse effect on our business.
We, our service providers and our customers are subject to complex federal, state and local laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.
Our development and production operations and the transportation of our products to market are subject to complex and stringent federal, state and local laws and regulations, including those governing protection of the environment and natural resources, the occupational health and safety aspects of our operations, the discharge of materials into the environment, and the protection of certain plant and animal species. See “Other – Environmental Regulation” in Item 1 of Part I of this Annual Report for a description of the laws and regulations that affect us. These laws and regulations require us, our service providers and our customers to obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. Environmental regulations may restrict the types, quantities and concentration of materials that may be released into the environment in connection with drilling and production activities, limit or prohibit drilling or transportation activities on certain lands lying within wilderness, wetlands, archeological sites and other protected areas, and impose substantial liabilities for pollution resulting from our operations and those of our service providers and customers. Moreover, we or they may experience delays in obtaining or be unable to obtain required permits, including as a result of government shutdowns, which may delay or interrupt our or their operations and limit our growth and revenues.
Failure to comply with laws and regulations can trigger a variety of administrative, civil and criminal enforcement measures, including investigatory actions, the assessment of monetary penalties, the imposition of remedial requirements, or the issuance of orders or judgments limiting or enjoining future operations. Strict liability or joint and several liability may be imposed under certain laws, which could cause us to become liable for the conduct of others or for consequences of our own actions. Moreover, our costs of compliance with existing laws could be substantial and may increase or unforeseen liabilities could be imposed if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. If we are not able to recover the increased costs through insurance or increased revenues, our business, financial condition, results of operations and cash flows could be adversely affected.
Risks Related to Financial Markets and Uncertainties
The trading price and volume of our common stock may be volatile, and you could lose a significant portion of your investment.
The market price of the common stock could be volatile, and holders of common stock may not be able to resell their common stock at or above the price at which they acquired such securities due to fluctuations in the market price of common stock. The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of the common stock. Specific factors that may have a significant effect on the market price for our common stock include:
•general economic conditions within the U.S. and internationally, including inflationary pressures and changes in interest rates;
•general market conditions, including fluctuations in commodity prices;
•domestic and international economic, legal and regulatory factors unrelated to our performance;
•changes in oil and natural gas prices;
•volatility in the financial markets or other global economic factors;
•actual or anticipated fluctuations in our and our competitors’ quarterly and annual results;
•quarterly variations in the rate of growth of our financial indicators;
•our business, operations, results and prospects;
•our operating and financial performance;
•future mergers and acquisitions, divestitures, joint ventures or similar strategic alliances;
•market conditions in the energy industry;
•changes in government regulation, taxes, legal proceedings or other developments;
•shortfalls in our operating results from levels forecasted by securities analysts;
•investor sentiment toward the stock of oil and gas companies;
•changes in revenue or earnings estimates, or changes in recommendations by equity research analysts;
•failure to achieve the perceived benefits of the acquisitions, including financial results and anticipated synergies, as rapidly as or to the extent anticipated by financial or industry analysts;
•speculation in the press or investment community;
•the failure of research analysts to cover our stock;
•sales of common stock by us, large shareholders or management, or the perception that such sales may occur;
•changes in accounting principles, policies, guidance, interpretations or standards;
•announcements concerning us or our competitors;
•public reaction to our press releases, other public announcements and filings with the SEC;
•strategic actions taken by competitors;
•actions taken by our shareholders;
•additions or departures of key management personnel;
•maintenance of acceptable credit ratings or credit quality; and
•the general state of the securities markets.
These and other factors may impair the market for the common stock and the ability of investors to sell shares at an attractive price. These factors also could cause the market price and demand for the common stock to fluctuate substantially, which may negatively affect the price and liquidity of the common stock. Many of these factors and conditions are beyond our control.
Securities class action litigation has often been instituted against companies following periods of volatility in the overall market and in the market price of a company’s securities. Such litigation, if instituted against us, could result in very substantial costs, divert management’s attention and resources and harm our business, operating results and financial condition.
Market views of our industry generally can affect our stock price, liquidity and ability to obtain financing.
Factors described elsewhere, including views regarding future commodity prices, regulation and climate change, can affect the amount investors choose to invest in our industry generally. Recent years have seen a significant reduction in overall investment in exploration and production companies, resulting in a drop in individual companies’ stock prices. Separate from actual and possible governmental action, certain financial institutions have announced policies to cease investing or to divest investments in companies, such as ours, that produce fossil fuels, and some banks have announced they no longer will lend to companies in this sector. To date these represent small fractions of overall sources of equity and debt, but that fraction could grow and thus affect our access to capital. Moreover, some equity investors are expressing concern over these matters and may prompt companies in our industry to adopt more costly practices even absent governmental action. Although we believe our practices result in low emission rates for methane and other greenhouse gases as compared to others in our industry, complying with investor sentiment may require modifications to our practices, which could increase our capital and operating expenses.
Volatility in the financial markets or in global economic factors could adversely impact our business and financial condition.
Our business may be negatively impacted by adverse economic conditions or future disruptions in global financial markets. Included among these potential negative impacts are reduced energy demand and lower commodity prices, including due to the impact of pandemics, increased difficulty in collecting amounts owed to us by our customers and reduced access to credit markets. Our ability to access the capital markets may be restricted at a time when we would like, or need, to raise financing. If financing is not available when needed, or is available only on unfavorable terms, we may be unable to implement our business plans or otherwise take advantage of business opportunities or respond to competitive pressures. Historically, the United States and global economies and financial systems have experienced extreme volatility in prices of equity and debt securities, periods of diminished liquidity and credit availability, inability to access capital markets, the bankruptcy, failure, collapse, or sale of financial institutions, inflation, and an unprecedented level of intervention by the United States federal government and other governments. Weakness or uncertainty in the United States economy or other large economies could materially adversely affect our business and financial condition.
Any changes in U.S. trade policy could trigger retaliatory actions by affected countries, resulting in “trade wars,” in increased costs for materials necessary for our industry along with other goods imported into the United States, which may reduce customer demand for these products if the parties having to pay those tariffs increase their prices, or in trading partners limiting their trade with the United States. If these consequences are realized, the volume of economic activity in the United States, including growth in sectors that utilize our products, may be materially reduced along with a reduction in the potential export of our products. Such a reduction may materially and adversely affect commodity prices, our sales and our business.
Risks Related to the Ability of our Hedging Activities to Adequately Manage our Exposure to Commodity and Financial Risk
Our commodity price risk management and measurement systems and economic hedging activities might not be effective and could increase the volatility of our results.
We currently seek to hedge the price of a significant portion of our estimated production through swaps, collars, floors and other derivative instruments. The systems we use to quantify commodity price risk associated with our businesses might not always be effective. Further, such systems do not in themselves manage risk, particularly risks outside of our control, and adverse changes in energy commodity market prices, volatility, adverse correlation of commodity prices, the liquidity of markets, changes in interest rates and other risks discussed in this report might still adversely affect our earnings, cash flows and balance sheet under applicable accounting rules, even if risks have been identified. Furthermore, no single hedging arrangement can adequately address all risks present in a given contract. For example, a forward contract that would be effective in hedging commodity price volatility risks would not hedge the contract’s counterparty credit or performance risk. Therefore, unhedged risks will always continue to exist.
Our use of derivatives, through which we attempt to reduce the economic risk of our participation in commodity markets could result in increased volatility of our reported results. Changes in the fair values (gains and losses) of derivatives that qualify
as hedges under GAAP to the extent that such hedges are not fully effective in offsetting changes to the value of the hedged commodity, as well as changes in the fair value of derivatives that do not qualify or have not been designated as hedges under GAAP, must be recorded in our income. This creates the risk of volatility in earnings even if no economic impact to us has occurred during the applicable period. To the extent we cap or lock prices at specific levels, we would also forgo the ability to realize the higher revenues that would be realized should prices increase.
The impact of changes in market prices for natural gas, oil and NGLs on the average prices paid or received by us may be reduced based on the level of our hedging activities. These hedging arrangements may limit or enhance our margins if the market prices for oil, natural gas or NGLs were to change substantially from the price established by the hedges. In addition, our hedging arrangements expose us to the risk of financial loss if our production volumes are less than expected.
The implementation of derivatives legislation and changes in regulatory interpretation and action could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.
The Dodd-Frank Act established federal oversight and regulation of the over-the-counter derivatives market and entities, including us, which participate in that market. The Dodd-Frank Act requires the CFTC, the SEC, and other regulatory authorities to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized most of its regulations under the Dodd-Frank Act, it continues to review and refine its initial rulemakings through additional interpretations and supplemental rulemakings. As a result, it is not possible at this time to predict the ultimate effect of the rules and regulations on our business and while most of the regulations have been adopted, any new regulations or modifications to existing regulations may increase the cost of derivative contracts, limit the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and the regulations thereunder, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital investing.
The CFTC imposes regulations that place federal limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. The CFTC also has a companion rule on aggregation of positions among entities under common ownership or control. It is too early to determine the precise effect of these rules on our business, but they may have an impact on our ability to hedge our exposure to certain enumerated commodities (whether using futures contracts, over-the-counter derivatives contracts or otherwise).
The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and mandatory trading on designated contract markets or swap execution facilities. The CFTC may designate additional classes of swaps as subject to the mandatory clearing requirement in the future, but has not yet proposed rules designating any other classes of swaps, including physical commodity swaps, for mandatory clearing. The CFTC and prudential banking regulators also adopted mandatory margin requirements on uncleared swaps between swap dealers and certain other counterparties. The margin requirements are currently effective with respect to certain market participants. We expect to qualify for and rely upon an end-user exception from the mandatory clearing and trade execution requirements for swaps entered to hedge our commercial risks. We also should qualify for an exception from the uncleared swaps margin requirements. However, the application of the mandatory clearing and trade execution requirements and the uncleared swaps margin requirement to other market participants, such as swap dealers, may adversely affect the cost and availability of the swaps that we use for hedging.
Risks Related to the Proposed Merger with Chesapeake
Because the Exchange Ratio is fixed and the market price of Chesapeake common stock has fluctuated and will continue to fluctuate, the Company's shareholders cannot be sure of the value of the consideration they will receive in the Proposed Merger.
If the Proposed Merger is completed, each eligible share of the Company's common stock outstanding immediately prior to the Proposed Merger will automatically be converted into the right to receive 0.0867 shares of Chesapeake common stock (the “Exchange Ratio”), with cash to be paid in lieu of fractional shares. Because the Exchange Ratio is fixed, the value of the Proposed Merger consideration will depend on the market price of Chesapeake common stock at the time the Proposed Merger is completed. Prior to completion of the Proposed Merger, the market price of Chesapeake common stock is also expected to impact the market price of the Company's common stock. The value of Chesapeake common stock has fluctuated since the date of the announcement of the Merger Agreement and will continue to fluctuate. Accordingly, the Company's shareholders will not know or be able to determine the market value of the Proposed Merger consideration they would receive upon completion of the Proposed Merger. Share price changes may result from a variety of factors, including, among others, general market and economic conditions, commodity prices, changes in Chesapeake's and the Company's respective businesses, operations and
prospects, market assessments of the likelihood that the Proposed Merger will be completed and the timing of the Proposed Merger and regulatory considerations. Many of these factors are beyond Chesapeake's and the Company's control.
The Proposed Merger is subject to various closing conditions, which may delay the Proposed Merger, result in additional expenditures of money and resources or reduce the anticipated benefits or result in the termination of the Merger Agreement.
On January 10, 2024, we entered into the Merger Agreement with Chesapeake, Merger Sub and LLC Sub, pursuant to which among other things, the Company will survive as a wholly owned subsidiary of Chesapeake. The Proposed Merger is subject to the satisfaction (or waiver, to the extent permissible under applicable laws) of a number of closing conditions described in the Merger Agreement, including Company shareholder approval of the Merger Agreement and transactions contemplated therein, Chesapeake shareholder approval of the issuance of shares of Chesapeake to the Company’s shareholders in connection with the Proposed Merger and certain regulatory approvals. Many of the closing conditions are beyond the parties’ control that may prevent, delay or otherwise materially adversely affect the completion of the Proposed Merger. The Company and Chesapeake cannot predict with certainty whether or when any of these conditions will be satisfied. If any of these conditions are not satisfied or waived prior to the Outside Date (as defined in the Merger Agreement), it is possible that the Merger Agreement may be terminated.
Although the parties have agreed to use reasonable best efforts, subject to certain limitations, to complete the Proposed Merger, these and other conditions may fail to be satisfied. In addition, completion of the Proposed Merger may take longer, and could cost more, than we expect. The requirements for obtaining the required clearances and approvals could delay the completion of the Proposed Merger for a significant period of time or prevent them from occurring. Any delay in completing the Proposed Merger may adversely affect the cost savings and other benefits that we expect to achieve if the Proposed Merger and the integration of businesses are completed within the expected timeframe.
The Merger Agreement subjects us to restrictions on our business activities prior to closing the Proposed Merger, limits the Company’s ability to pursue alternatives to the Proposed Merger and may discourage other companies from trying to acquire the Company for greater consideration than what Chesapeake has agreed to pay pursuant to the Merger Agreement.
The Merger Agreement subjects us to restrictions to our business activities prior to closing the Proposed Merger. The Merger Agreement obligates us to, until the closing, generally conduct our business in the ordinary course consistent with past practice and refraining from taking certain actions, excepting in each case actions expressly permitted or required by the Merger Agreement, required by law or consented to by the other party in writing. These restrictions could prevent us from pursuing certain business opportunities that arise prior to the closing and are outside the ordinary course of business.
The Merger Agreement also provides that, during the period from the date of the Merger Agreement until the Effective Time, the Company and Chesapeake will be subject to certain restrictions on their ability to solicit alternative acquisition proposals from third parties, to provide non-public information to third parties and to engage in discussions with third parties regarding alternative acquisition proposals, subject to customary exceptions as set forth in the Merger Agreement, and in certain cases, circumstances, upon termination of the Merger Agreement by Chesapeake, the Company will be required to pay a termination fee to Chesapeake, which in each case could make it more difficult for the Company to sell its business to a party other than Chesapeake. Additionally, even if our board changes, withdraws, modifies or qualifies its recommendation with respect to the Proposed Merger, unless the Merger Agreement is terminated in accordance with its terms, we will still be required to submit the Proposed Merger to a vote at our special meeting. While both the Company and Chesapeake believe these provisions and agreements are reasonable and customary and are not preclusive of other offers, these restrictions, including the added expense of the termination fee that may become payable by the Company to Chesapeake in certain circumstances, might discourage a third party that has an interest in acquiring all or a significant part of the Company from considering or proposing that acquisition, even if that party were prepared to pay consideration with a higher per-share value than the consideration payable in the Proposed Merger pursuant to the Merger Agreement.
Completion of the Proposed Merger is subject to certain closing conditions and if these conditions are not satisfied or waived, the Proposed Merger will not be completed and failure to complete the Proposed Merger could negatively impact the share price and the future business and financial results of the Company.
The consummation of the Proposed Merger is subject to the satisfaction or waiver of customary closing conditions described in the Merger Agreement, including Company shareholder approval of the Merger Agreement and transactions contemplated therein, Chesapeake shareholder approval of the issuance of shares of Chesapeake to the Company’s shareholders in connection with the Proposed Merger and certain regulatory approvals. The Merger Agreement contains customary representations and warranties of the Company and Chesapeake relating to their respective businesses, financial statements and public filings, in each case generally subject to customary materiality qualifiers. Additionally, the Merger Agreement provides for customary pre-
closing covenants of the Company and Chesapeake, including, subject to certain exceptions, covenants relating to conducting their respective businesses in the ordinary course consistent with past practice and refraining from taking certain actions, excepting in each case actions expressly permitted or required by the Merger Agreement, required by law or consented to by the other party in writing. There can be no assurance that the conditions to the closing of the Proposed Merger will be satisfied or waived or that the Proposed Merger will be completed.
If the Proposed Merger is not completed for any reason, including as a result of the Company's shareholders failing to approve the Proposed Merger or any other closing condition not being satisfied or waived, the ongoing businesses of the Company may be adversely affected, and without realizing any of the benefits of having completed the Proposed Merger, the Company would be subject to a number of risks, including:
•negative reactions from the financial markets, negative reactions on its stock price
•negative reactions from its customers, regulators and employees, and incurring certain costs related to the Proposed Merger, whether or not the Proposed Merger is completed
Additionally, the Proposed Merger will require substantial commitments of time and resources by the Company's management, which would otherwise have been devoted to day-to-day operations and other opportunities that may have been beneficial to the Company as an independent company and the Merger Agreement restricts the Company from pursuing certain opportunities during the pendency of the Proposed Merger that the Company would have made, taken or pursued if the restrictions in the Merger Agreement were not in place. There can be no assurance that the risks described above will not materialize. If any of those risks materialize, they may materially and adversely affect the Company's businesses, financial condition, financial results, ratings, bond prices and/or share price.
Potential litigation against the Company could result in substantial costs, an injunction preventing the completion of the Proposed Merger and/or a judgment resulting in the payment of damages.
Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into merger agreements. Even if such a lawsuit is without merit, defending against these claims can result in substantial costs and divert management time and resources. Shareholders of the Company may file lawsuits against Chesapeake, the Company and/or the directors and officers of either company in connection with the Proposed Merger. These lawsuits could prevent or delay the completion of the Proposed Merger and result in significant costs to the Company, including any costs associated with the indemnification of directors and officers. Additionally, if a plaintiff is successful in obtaining an injunction prohibiting the completion of the Proposed Merger, that injunction may delay or prevent the Proposed Merger from being completed within the expected timeframe or at all. There can be no assurance that any of the defendants will be successful in the outcome of any potential lawsuits.
The Company will incur significant transaction and merger-related costs in connection with the Proposed Merger.
The Company expects to incur a number of non-recurring costs associated with the- Proposed Merger and combining the operations of the two companies. The significant, non-recurring costs associated with the Proposed Merger include, among others, fees and expenses of financial advisors and other advisors and representatives, certain employment-related costs relating to employees of the Company, filing fees due in connection with filings required under the HSR Act and filing fees and printing and mailing costs for a proxy statement/prospectus. Some of these costs have already been incurred or may be incurred regardless of whether the Merger is completed, including a portion of the fees and expenses of financial advisors and other advisors and representatives and filing fees for a proxy statement/prospectus.
Our shareholders will have a reduced ownership and voting interest in the combined company after the Proposed Merger compared to their current ownership in the Company on a standalone basis and will exercise less influence over management.
Currently, the Company’s shareholders have the right to vote in the election of the Company’s board of directors and on other matters requiring shareholder approval under Delaware law and the Company’s certificate of incorporation and bylaws. As a result of the Proposed Merger, the Company’s current shareholders will own a smaller percentage of the combined company than they currently own of the Company, and as a result will have less influence on the management and policies of the combined company post-merger than they now have on the management and policies of the Company.
These risks are not the only risks facing the Company. Additional risks and uncertainties not currently known to the Company or that it currently deems to be immaterial also may have a material adverse effect on the Company's business, financial condition or future results.
The Company’s business relationships may be subject to disruption due to uncertainty associated with the Proposed Merger.
Parties with which the Company does business may experience uncertainty associated with the Proposed Merger, including with respect to current or future business relationships with Chesapeake, the Company or the combined business. The Company’s business relationships may be subject to disruption as parties with which Chesapeake or the Company does business may attempt to negotiate changes in existing business relationships or consider entering into business relationships with parties other than Chesapeake, the Company, or the combined business. These disruptions could have an adverse effect on the businesses, financial condition, results of operations or prospects of the combined business, including an adverse effect on Chesapeake’s ability to realize the anticipated benefits of the Proposed Merger. The risk, and adverse effect, of such disruptions could be exacerbated by a delay in completion of the Proposed Merger or termination of the Merger Agreement.
Uncertainties associated with the Proposed Merger may cause a loss of management personnel and other key employees of the Company and Chesapeake, which could adversely affect the future business and operations of the combined company following the Proposed Merger.
The Company and Chesapeake are dependent on the experience and industry knowledge of their respective officers and other key employees to execute their business plans. The combined company’s success after the Proposed Merger will depend in part upon its ability to retain key management personnel and other key employees of both the Company and Chesapeake. Current and prospective employees of the Company and Chesapeake may experience uncertainty about their roles within the combined company following the Proposed Merger or other concerns regarding the timing and completion of the Proposed Merger or the operations of the combined company following the Proposed Merger, any of which may have an adverse effect on the ability of the Company and Chesapeake to retain or attract key management and other key-personnel. If the Company and Chesapeake are unable to retain personnel, including key management, who are critical to the future operations of the companies, the Company and Chesapeake could face disruptions in their operations, loss of existing customers, loss of key information, expertise or know-how and unanticipated additional recruitment and training costs. In addition, the loss of key personnel could diminish the anticipated benefits of the Proposed Merger.
ITEM 1B. UNRESOLVED STAFF COMMENTS.
None.
ITEM 1C. CYBERSECURITY
Rapidly evolving cyber techniques and increased cybersecurity threats against energy and critical infrastructure companies have raised the level of risk across our industry in recent years. Greater use of technology and digitization in operations has delivered benefits to our business, while also opening the industry to new vulnerabilities in corporate and operational systems. The energy industry remains subject to evolving cybersecurity threats and actors, including criminals, terrorists and nation states and through insiders and third-party breaches.
The scale, scope, and complexity of our business raises a multitude of interdependent risks, which can vary over time. A primary responsibility of our Executive Leadership Team (“ELT”), subject to oversight by our Board of Directors and specifically, our Audit Committee, is to design and implement rigorous processes to identify, prioritize, assess monitor, and manage enterprise-level risks, including any material risks associated with cybersecurity threats. Our Enterprise Risk Management (“ERM”) team directly oversees the ERM process which incorporates input from personnel from different functions, levels, and operating regions (collectively, the “cross functional team”) to support a high level of visibility and accountability throughout the company and to incorporate multiple vantage points on risks and potential mitigations. Our Chief Financial Officer leads and oversees the ERM team with input from other ELT members and the cross-functional team. The ERM team meets at least quarterly to discuss key risks and to discuss mitigation strategies. The results of our ERM process are communicated to the Board at least annually.
Cybersecurity is recognized as a top enterprise risk and is managed by our Business Information Systems (“BIS”) team, a cross-functional team, which is led by our Vice President of Business Information Systems (“VP of BIS”), which reports to the ERM team on a quarterly basis. The Audit Committee of the Board of Directors oversees cybersecurity risks and receives quarterly cybersecurity reports from our VP of BIS and conducts at least two in-depth cybersecurity discussions annually. Our VP of BIS has more than 35 years of experience in Information Technology, including cybersecurity leadership roles. Our Director of Information Security, who reports directly to the VP of BIS, has over 20 years of experience in Information Security Management
and maintains Certified Information Security Manager (“CISM”) and Certified Data Privacy Solutions Engineer (“CDPSE”) certifications.
As part of our cybersecurity incident response plan, we have also established a cybersecurity incident escalation process whereby potential cybersecurity incidents are identified, monitored, assessed, and escalated to our Cybersecurity Disclosure Committee (“CSDC”), as appropriate. The CSDC is comprised of members of our ELT and representatives from our Business Information Systems, including our VP of BIS, Accounting, Legal and Internal Audit departments. The CSDC assists in evaluating qualitative and quantitative factors related to the cybersecurity incident in order to assess the impact of such cybersecurity incidents and to disclose the incident should we determine that the cybersecurity incident is material. The Audit Committee or its designee will be made aware of material cybersecurity incidents in the event they occur.
Protection of our informational assets is managed by a comprehensive, multilayer strategy modeled on the National Institute of Standards and Technology (“NIST”) cybersecurity framework, and combines assessments, technology, services, policies, and user education to detect, prevent, mitigate and remediate cybersecurity incidents and related risks. However, this does not imply that we meet any particular technical standards, specifications, or requirements. We have instituted cybersecurity-related policies and procedures, which are key components of our cyber defense and our efforts to protect employees and contractors, while encouraging partnerships only with responsible vendors who also invest in effective cybersecurity practices.
Our processes also address cybersecurity threat risks associated with our use of third-party service providers, including those in our supply chain or who have access to our data or our systems. Third-party risks are included within our ERM assessment program.
We conduct regular, proactive cybersecurity vulnerability assessments to identify opportunities for improvement and reduce exposure to cybersecurity incidents. We also conduct regular cyber incident simulations and undergo internal and external audits of our processes. We participate in industry organizations, engage third-party service providers, and maintain close working relationships with law enforcement agencies to help us identify and address the latest cybersecurity threats.
In addition, we participate in the Department of Homeland Security’s Cyber Resilience Review (“CRR”), a voluntary, nontechnical assessment to evaluate an organization’s operational resilience and cybersecurity practices. The CRR assesses enterprise programs and practices across a range of 10 domains, including risk management, incident management and service continuity.
To date, we have not experienced any material losses or interruptions relating to cybersecurity incidents; however, there can be no assurance that we will not suffer such losses in the future. For further discussion regarding cybersecurity risks and their impact on our business strategy, results of operations and financial condition, see the risk factor entitled “A cyber incident could result in information theft, data corruption, operational disruption and/or financial loss” under the heading “Risk Factors” in Item 1A of this Annual Report. ITEM 2. PROPERTIES
The summary of our oil and natural gas reserves as of fiscal year-end 2023 based on average fiscal-year prices, as required by Item 1202 of Regulation S-K, is included in the table headed “2023 Proved Reserves by Category and Summary Operating Data” in “Business – Exploration and Production – Our Proved Reserves” in Item 1 of this Annual Report and incorporated by reference into this Item 2. The information regarding our proved undeveloped reserves required by Item 1203 of Regulation S-K is included under the heading “Proved Undeveloped Reserves” in “Business – Exploration and Production – Our Proved Reserves” in Item 1 of this Annual Report and incorporated by reference in this Item 2.
The information regarding natural gas and oil properties, wells, operations and acreage required by Item 1208 of Regulation S-K is set forth below:
Leasehold acreage as of December 31, 2023
The following table sets forth our gross and net developed and undeveloped natural gas and oil leasehold and fee mineral acreage as of December 31, 2023. Gross acres are the total number of acres in which we own a working interest. Net acres refer to gross acres multiplied by our fractional working interest.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Undeveloped | | Developed | | Total |
| Gross | | Net | | Gross | | Net | | Gross | | Net |
| Appalachia | 552,091 | | | 387,992 | | | 398,129 | | | 330,568 | | | 950,220 | | | 718,560 | |
| Haynesville | 38,187 | | | 32,875 | | | 340,463 | | | 248,486 | | | 378,650 | | | 281,361 | |
| Other: | | | | | | | | | | | |
| US – Other Exploration | — | | | — | | | 5,034 | | | 2,263 | | | 5,034 | | | 2,263 | |
| | | | | |
| Total US | 590,278 | | | 420,867 | | | 743,626 | | | 581,317 | | | 1,333,904 | | | 1,002,184 | |
Canada – New Brunswick (1) | 2,518,519 | | | 2,518,519 | | | — | | | — | | | 2,518,519 | | | 2,518,519 | |
| 3,108,797 | | | 2,939,386 | | | 743,626 | | | 581,317 | | | 3,852,423 | | | 3,520,703 | |
(1)The exploration licenses for 2,518,519 net acres in New Brunswick, Canada, were extended through March 2026 but have been subject to a moratorium since 2015. We fully impaired our investment in New Brunswick in 2016. Unless and until the moratorium is lifted, we will not be able to develop these assets.
Lease Expirations
The following table summarizes the leasehold acreage expiring over the next three years, assuming successful wells are not drilled to develop the acreage and leases are not extended:
| | | | | | | | | | | | | | | | | |
| For the years ended December 31, |
| Net acreage expiring: | 2024 | | 2025 | | 2026 |
Appalachia (1) | 17,598 | | | 8,421 | | | 4,736 | |
| Haynesville | 630 | | | 2,083 | | | 319 | |
| Other: | | | | | |
| US – Other Exploration | — | | | — | | | — | |
|
Canada – New Brunswick (2) | — | | | — | | | — | |
(1)The leasehold acreage expiring includes 14,341 net acres in 2024, 2,984 net acres in 2025 and 2,036 net acres in 2026 which can be extended for an average of three to five years.
(2)Exploration licenses were extended through March 2026 but have been subject to a moratorium since 2015. We fully impaired our investment in New Brunswick in 2016. Unless and until the moratorium is lifted, we will not be able to develop these assets.
Producing wells as of December 31, 2023
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Natural Gas | | Oil | | Total | | Gross Wells Operated |
| Gross | | Net | | Gross | | Net | | Gross | | Net | |
| Appalachia | 1,879 | | | 1,485.7 | | | 2 | | | 0.6 | | | 1,881 | | | 1,486.3 | | | 1,647 | |
| Haynesville | 1,149 | | | 745.8 | | | — | | | — | | | 1,149 | | | 745.8 | | | 772 | |
| | | | | | | |
| 3,028 | | | 2,231.5 | | | 2 | | | 0.6 | | | 3,030 | | | 2,232.1 | | | 2,419 | |
The information regarding drilling and other exploratory and development activities required by Item 1205 of Regulation S-K is set forth below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Development |
| | Productive Wells | | Dry Wells | | Total |
| Year | | Gross | | Net | | Gross | | Net | | Gross | | Net |
| 2023 | | | | | | | | | | | | |
| Appalachia | | 67.0 | | | 56.0 | | | — | | | — | | | 67.0 | | | 56.0 | |
Haynesville (1) | | 65.0 | | | 59.3 | | | — | | | — | | | 65.0 | | | 59.3 | |
| Total | | 132.0 | | | 115.3 | | | — | | | — | | | 132.0 | | | 115.3 | |
| 2022 | | | | | | | | | | | | |
| Appalachia | | 63.0 | | | 54.2 | | | — | | | — | | | 63.0 | | | 54.2 | |
Haynesville (1) | | 70.0 | | | 63.5 | | | — | | | — | | | 70.0 | | | 63.5 | |
| Total | | 133.0 | | | 117.7 | | | — | | | — | | | 133.0 | | | 117.7 | |
| 2021 | | | | | | | | | | | | |
| Appalachia | | 78.0 | | | 74.8 | | | — | | | — | | | 78.0 | | | 74.8 | |
Haynesville (1) | | 15.0 | | | 14.5 | | | — | | | — | | | 15.0 | | | 14.5 | |
| Total | | 93.0 | | | 89.3 | | | — | | | — | | | 93.0 | | | 89.3 | |
(1)The Haynesville E&P assets were acquired through the Indigo Merger and GEPH Merger in September 2021 and December 2021, respectively.
The Company drilled no exploratory wells (productive or dry) in any of its areas of operation during the three years ended December 31, 2023.
The following table presents the information regarding our present activities required by Item 1206 of Regulation S-K:
Wells in progress as of December 31, 2023
| | | | | | | | | | | |
|
| Drilling: | Gross | | Net |
| Appalachia | 5.0 | | | 5.0 | |
| Haynesville | 18.0 | | | 17.4 | |
| Total | 23.0 | | | 22.4 | |
| Completing: | | | |
| Appalachia | 17.0 | | | 14.5 | |
| Haynesville | 13.0 | | | 12.9 | |
| Total | 30.0 | | | 27.4 | |
| Drilling & Completing: | | | |
| Appalachia | 22.0 | | | 19.5 | |
| Haynesville | 31.0 | | | 30.3 | |
| Total | 53.0 | | | 49.8 | |
The information regarding oil and gas production, production prices and production costs required by Item 1204 of Regulation S-K is set forth below:
Production, Average Sales Price and Average Production Cost
| | | | | | | | | | | | | | | | | |
| For the years ended December 31, |
| 2023 | | 2022 | | 2021 |
| Natural Gas | | | | | |
Production (Bcf): | | | | | |
| Appalachia | 803 | | | 841 | | | 883 | |
Haynesville (1) | 635 | | | 679 | | | 132 | |
|
| Total | 1,438 | | | 1,520 | | | 1,015 | |
| | | | | |
Average realized gas price, excluding derivatives ($/Mcf): | | | | | |
| Appalachia | $ | 1.83 | | | $ | 5.75 | | | $ | 3.03 | |
Haynesville (1) | $ | 2.46 | | | $ | 6.27 | | | $ | 5.18 | |
| Total | $ | 2.11 | | | $ | 5.98 | | | $ | 3.31 | |
| | | | | |
Average realized gas price, including derivatives ($/Mcf): | $ | 2.36 | | | $ | 2.79 | | | $ | 2.28 | |
| | | | | |
| Oil | | | | | |
Production (MBbls): | | | | | |
| Appalachia | 5,568 | | | 4,967 | | | 6,567 | |
Haynesville (1) | 30 | | | 20 | | | 8 | |
| Other | 4 | | | 6 | | | 35 | |
| Total | 5,602 | | | 4,993 | | | 6,610 | |
| | | | | |
Average realized oil price, excluding derivatives ($/Bbl): | | | | | |
| Appalachia | $ | 66.80 | | | $ | 86.92 | | | $ | 58.82 | |
Haynesville (1) | $ | 74.65 | | | $ | 94.68 | | | $ | 62.54 | |
| Other | $ | 74.37 | | | $ | 86.05 | | | $ | 55.29 | |
| Total | $ | 66.84 | | | $ | 86.95 | | | $ | 58.80 | |
| | | | | |
Average realized oil price, including derivatives ($/Bbl): | $ | 57.21 | | | $ | 50.83 | | | $ | 40.48 | |
| | | | | |
| NGL | | | | | |
Production (MBbls): | | | | | |
| Appalachia | 32,848 | | | 30,445 | | | 30,936 | |
|
| Other | 11 | | | 1 | | | 4 | |
| Total | 32,859 | | | 30,446 | | | 30,940 | |
| | | | | |
Average realized NGL price, excluding derivatives ($/Bbl): | | | | | |
| Appalachia | $ | 21.38 | | | $ | 34.35 | | | $ | 28.72 | |
|
| Other | $ | 28.29 | | | $ | — | | | $ | 40.98 | |
| Total | $ | 21.38 | | | $ | 34.35 | | | $ | 28.72 | |
| | | | | |
Average realized NGL price, including derivatives ($/Bbl) | $ | 22.46 | | | $ | 26.52 | | | $ | 18.20 | |
(1)The Haynesville E&P assets were acquired through the Indigo Merger and GEPH Merger in September 2021 and December 2021, respectively. |
| | | | | | | | | | | | | | | | | |
| For the years ended December 31, |
| 2023 | | 2022 | | 2021 |
Total Production by Area (Bcfe) | | | | | |
| Appalachia | 1,034 | | | 1,054 | | | 1,108 | |
Haynesville (1) | 635 | | | 679 | | | 132 | |
|
| Total | 1,669 | | | 1,733 | | | 1,240 | |
| | | | | |
Total Production by Formation (Bcfe) | | | | | |
| Marcellus Shale | 917 | | | 891 | | | 943 | |
| Utica Shale | 117 | | | 166 | | | 164 | |
Haynesville Shale (1) | 374 | | | 411 | | | 100 | |
Bossier Shale (1) | 261 | | | 262 | | | 32 | |
| Other | — | | | 3 | | | 1 | |
| Total | 1,669 | | | 1,733 | | | 1,240 | |
| | | | | |
| Lease Operating Expense | | | | | |
| Cost per Mcfe, excluding ad valorem and severance taxes: | | | | | |
| Appalachia | $ | 1.15 | | | $ | 1.06 | | | $ | 0.95 | |
Haynesville (1) | $ | 0.89 | | | $ | 0.87 | | | $ | 0.88 | |
| Total | $ | 1.05 | | | $ | 0.98 | | | $ | 0.95 | |
(1)The Haynesville E&P assets were acquired through the Indigo Merger and GEPH Merger in September 2021 and December 2021, respectively.
During 2023, we were required to file Form 23, “Annual Survey of Domestic Oil and Gas Reserves,” with the U.S. Department of Energy. The basis for reporting reserves on Form 23 is not comparable to the reserve data included in “Supplemental Oil and Gas Disclosures” in Item 8 of Part II of this Annual Report. The primary differences are that Form 23 reports gross reserves, including the royalty owners’ share, and includes reserves for only those properties of which we are the operator. Title to Properties
We believe that we have satisfactory title to substantially all of our active properties in accordance with standards generally accepted in the oil and natural gas industry. Our properties are subject to customary royalty and overriding royalty interests, certain contracts relating to the exploration, development, operation and marketing of production from such properties, consents to assignment and preferential purchase rights, liens for current taxes, applicable laws and other burdens, encumbrances and irregularities in title, which we believe do not materially interfere with the use of or affect the value of such properties. Prior to acquiring undeveloped properties, we endeavor to perform a title investigation that is thorough but less vigorous than that we endeavor to conduct prior to drilling, which is consistent with standard practice in the oil and natural gas industry. Generally, before we commence drilling operations on properties that we operate, we conduct a title examination and perform curative work with respect to significant defects that we identify. We believe that we have performed title review with respect to substantially all of our active properties that we operate.
ITEM 3. LEGAL PROCEEDINGS
We are subject to various litigation, claims and proceedings that arise in the ordinary course of business, such as for alleged breaches of contract, miscalculation of royalties, employment matters, traffic incidents, pollution, contamination, encroachment on others’ property or nuisance. We accrue for such items when a liability is both probable and the amount can be reasonably estimated. It is not possible at this time to estimate the amount of any additional loss, or range of loss that is reasonably possible, but based on the nature of the claims, management believes that current litigation, claims and proceedings, individually or in aggregate and after taking into account insurance, are not likely to have a material adverse impact on our financial position, results of operations or cash flows, for the period in which the effect of that outcome becomes reasonably estimable. Many of these matters are in early stages, so the allegations and the damage theories have not been fully developed, and are all subject to inherent uncertainties; therefore, management’s view may change in the future. If an unfavorable final outcome were to occur, there exists the possibility of a material impact on our financial position, results of operations or cash flows for the period in which the effect becomes reasonably estimable.
We are also subject to laws and regulations relating to the protection of the environment. Environmental and cleanup related costs of a non-capital nature are accrued when it is both probable that a liability has been incurred and when the amount can be reasonably estimated. Management believes any future remediation or other compliance related costs will not have a material effect on our financial position or results of operations.
See “Litigation” in Note 10 to the consolidated financial statements included in this Annual Report for further details on our current legal proceedings. ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock is traded on the NYSE under the symbol “SWN.” On February 20, 2024, the closing price of our common stock was $6.61 and we had 1,768 stockholders of record.
We currently do not pay dividends on our common stock, and we do not anticipate paying any cash dividends in the foreseeable future. All decisions regarding the declaration and payment of dividends and stock repurchases are at the discretion of our Board of Directors and will be evaluated regularly in light of our financial condition, earnings, growth prospects, funding requirements, applicable law and any other factors that our Board of Directors deems relevant.
See Part III, Item 12, “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” and Note 14 to our consolidated financial statements included in Part II, Item 8, “Financial Statements and Supplementary Data” for information regarding shares of common stock authorized for issuance under our stock compensation plans.
Issuer Purchases of Equity Securities
None.
Recent Sales of Unregistered Equity Securities
None.
STOCK PERFORMANCE GRAPH
The following graph compares, for the last five years, the performance of our common stock to the S&P 500 Index and the S&P Oil and Gas Exploration and Production Select Industry Index. The chart assumes that the value of the investment in our common stock and each index was $100 at December 31, 2018 and that all dividends were reinvested. The stock performance shown on the graph below is not indicative of future price performance:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | 2023 |
| Southwestern Energy Company | $ | 100 | | | $ | 71 | | | $ | 87 | | | $ | 137 | | | $ | 172 | | | $ | 192 | |
| S&P 500 Index | 100 | | | 131 | | | 156 | | | 200 | | | 164 | | | 207 | |
S&P Oil and Gas Exploration and Production Select Industry Index | 100 | | | 91 | | | 58 | | | 97 | | | 141 | | | 146 | |
ITEM 6. [RESERVED]
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Management’s Discussion and Analysis is the Company’s analysis of its financial performance and of significant trends that may affect future performance. It should be read in conjunction with the financial statements and notes, and supplemental oil and gas disclosures included elsewhere in this report. It contains forward-looking statements including, without limitation, statements relating to the Company’s plans, strategies, objectives, expectations and intentions that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. In many cases you can identify forward-looking statements by words such as “anticipate,” “intend,” “plan,” “project,” “estimate,” “continue,” “potential,” “should,” “could,” “may,” “will,” “objective,” “guidance,” “outlook,” “effort,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “forecast,” “target” or similar words. Unless required to do so under the federal securities laws, the Company does not undertake to update, revise or correct any forward-looking statements, whether as a result of new information, future events or otherwise. Readers are cautioned that such forward-looking statements should be read in conjunction with the Company’s disclosures under the heading: “Cautionary Statement about Forward-Looking Statements” in this Annual Report. Also, see the risk factors and other cautionary statements described under the heading “Risk Factors” in Item 1A of this Annual Report. OVERVIEW
Proposed Merger with Chesapeake
On January 10, 2024, the Company entered into a Merger Agreement with Chesapeake, Merger Sub and LLC Sub, pursuant to which, among other things, the Company will survive as a wholly owned subsidiary of Chesapeake. Under the terms of the Merger Agreement, each eligible share of the Company's common stock will be converted into the right to receive 0.0867 shares of Chesapeake common stock. Completion of the Proposed Merger remains subject to certain conditions, including the approval of the Proposed Merger by the Company's shareholders, approval by Chesapeake shareholders of the issuance of Chesapeake common stock in connection with the Proposed Merger, as well as certain governmental and regulatory approvals. The Proposed Merger is currently targeted to close in the second quarter of 2024; however, no assurance can be given as to when, or if, the Proposed Merger will occur.
The above description of the Merger Agreement and the transactions contemplated thereby, including certain referenced terms, is a summary of certain principal terms and conditions contained in the Merger Agreement, a copy of which is attached as Exhibit 2.1 to the Company’s Current Report on Form 8-K, filed January 11, 2024.
See Note 16 - Subsequent Events of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements" for additional information. Also, see the risk factors and other cautionary statements, specifically, Risks Related to the Proposed Merger with Chesapeake under the heading “Risk Factors” in Item 1A of this Annual Report. Background
We are an independent energy company engaged in natural gas, oil and NGLs development, exploration and production, which we refer to as “E&P.” We are also focused on creating and capturing additional value through our marketing business, which we call “Marketing”. We conduct most of our businesses through subsidiaries, and we currently operate exclusively in the Appalachian and Haynesville natural gas basins in the lower 48 United States.
E&P. Our primary business is the development and production of natural gas as well as associated NGLs and oil, with our ongoing operations focused on the development of unconventional natural gas reservoirs located in Pennsylvania, West Virginia, Ohio and Louisiana. Our operations in Pennsylvania, West Virginia and Ohio, which we refer to as “Appalachia,” are focused on the Marcellus Shale, the Utica and the Upper Devonian unconventional natural gas and liquids reservoirs. Our operations in Louisiana, which we refer to as “Haynesville,” are primarily focused on the Haynesville and Bossier natural gas reservoirs and give us additional exposure to the LNG corridor and other markets on the U.S. Gulf Coast. We also have drilling rigs located in Appalachia and Haynesville, and we provide certain oilfield products and services, principally serving our E&P operations through vertical integration.
Marketing. Our marketing activities capture opportunities that arise through the marketing and transportation of natural gas, oil, and NGLs primarily produced in our E&P operations.
Focus in 2023. We continued our disciplined approach of optimizing free cash flow throughout 2023. This approach balanced our dual priorities of debt reduction and managing our productive capacity for what we expect will be an improving natural gas price environment in the future. We used our free cash flow in 2023 along with a sale of select non-core assets and positive working capital to pay down debt by $445 million, strengthen our balance sheet and improve our debt leverage metrics.
Improving our ability to generate free cash flow through the cycle is an important part of our strategy to strengthen our balance sheet. Our long-term goal is to incorporate a sustainable cash return component into our overall economic return for shareholders. Our near-term strategic goal is to prioritize the use of any free cash flow to improve our financial strength by reducing our debt to achieve our debt target range and, secondarily, returning value to shareholders.
Free cash flow is a non-GAAP financial measure. We define free cash flow as net cash provided by operating activities, adjusted for (i) changes in assets and liabilities and (ii) cash transaction costs associated with mergers and restructuring, less capital investments. Free cash flow is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We believe free cash flow can provide an indicator of excess cash flow available to a company for the repayment of debt or for other general corporate purposes, as it disregards the timing of settlements of operating assets and liabilities.
For a discussion of climate change matters and related regulatory matters, including potential developments related to climate change and the potential impacts and risks of such developments on us, see “Risk Factors” in Item 1A of this Annual Report, and the related discussion in “Business – Other – Environmental Regulation” in Item 1 of this Annual Report. We will continue to monitor and assess any climate change-related developments that could impact us and the oil and gas industry, to determine the impact on our business and operations, and take appropriate actions where necessary.
Natural gas, oil and NGL price fluctuations present challenges to our industry and our Company, as do changes in laws, regulations and investor sentiment and other key factors described under “Risk Factors” in Item 1A of this Annual Report. Although we currently expect to maintain a rolling three-year derivative portfolio, there can be no assurance that we will be able to add derivative positions to cover our expected production at favorable prices. See “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A and Note 6 - Derivatives and Risk Management, in the consolidated financial statements included in this Annual Report for further details. Recent Financial and Operating Results
Significant operating and financial highlights for 2023 include:
Total Company
•Net income of $1,557 million, or $1.41 per diluted share, declined from net income of $1,849 million, or $1.66 per diluted share, in 2022. Net income declined as a $8,328 million decrease in operating income, including $1,710 million of impairments charged in 2023, was partially offset by a $7,692 million increase in our derivative position due to the impact of lower forward pricing. Further offsetting the decline in net income in 2023 as compared to 2022 is a $257 million tax benefit in 2023 as compared to a $51 million tax provision in 2022 and $42 million decrease in interest expense year over year.
•Operating income decreased from $7,354 million for the year ended December 31, 2022 to an operating loss of $974 million for the year ended December 31, 2023. Operating income decreased by $8,328 million as a $8,480 million decrease in operating revenues, mostly attributable to lower pricing in 2023 compared to 2022, was partially offset by decreased operating costs of $152 million.
•Net cash provided by operating activities of $2,516 million decreased 20% from $3,154 million in 2022, primarily due to a $6,114 million decrease resulting from lower commodity prices, a $354 million decrease related to decreased production and a $7 million decrease in our marketing margin. The decreases were partially offset by a $5,628 million increase in our settled derivative position, a $119 million increased impact of working capital, a $56 million decrease in current taxes and a $42 million decrease in interest expense.
•Net cash provided by operating activities, net of changes in working capital, was $2,273 million for the year ended December 31, 2023, a $757 million decrease compared to the same period in 2022.
•Total capital invested of $2,131 million decreased 4% from $2,209 million in 2022 primarily due to lower activity levels associated with lower commodity pricing period over period.
E&P
•E&P segment operating loss was $1,061 million in 2023, compared to operating income of $7,253 million in 2022. The decrease in 2023 was primarily due to a $6,468 million decrease in E&P operating revenues resulting from a $3.64 per Mcfe decrease in our realized weighted average price (excluding derivatives) and a 64 Bcfe decrease in production volumes combined with a $1,846 million increase in E&P operating costs and expenses, including a non-cash full cost ceiling impairment of $1,710 million in 2023.
•2023 year-end reserves of 19,660 Bcfe decreased 1,965 Bcfe, or 9%, from 2022 year-end reserves of 21,625 Bcfe, as 1,972 Bcfe of downward revisions, 1,669 Bcfe of production and 350 Bcfe associated with properties that were sold were partially offset by 2,026 Bcfe of additions.
•Total net production of 1,669 Bcfe, which was comprised of 86% natural gas, 12% NGLs and 2% oil, decreased 4% from 1,733 Bcfe in 2022 resulting from our moderation of activity related to the decrease in near-term natural gas prices and the impact of inflation
•Excluding the effect of derivatives, our realized natural gas price of $2.11 per Mcf, realized oil price of $66.84 per barrel and realized NGL price of $21.38 per barrel decreased 65%, 23% and 38%, respectively, from 2022. Our weighted average realized price excluding the effect of derivatives of $2.46 per Mcfe decreased 60% from the same period in 2022.
•The E&P segment invested $2,122 million in capital; drilling 110 wells, completing 124 wells and placing 132 wells to sales.
Outlook
Our primary focus in 2024 is to continue our disciplined approach of optimizing our free cash flow generation activity through our dual priorities of debt reduction and managing our productive capacity.
As we continue to develop our core positions in the Appalachian and Haynesville natural gas basins in the U.S., we will concentrate on:
•Creating Sustainable Value. We seek to create value for our stakeholders by allocating capital that is focused on earning economic returns and optimizing the value of our assets; delivering sustainable free cash flow through the cycle; upgrading the quality and depth of our drilling inventory; enhancing the capital efficiency of our operations; and converting resources to proved reserves.
•Protecting Financial Strength. We intend to protect our financial strength by lowering our leverage ratio and total debt; maintaining a strong liquidity position and attractive debt maturity profile; improving our credit ratings and outlooks with the credit agencies; lowering our weighted average cost of debt; and deploying hedges to balance revenue protection with commodity upside exposure.
•Progressing Execution. We are focused on operating effectively and efficiently with HSE and ESG as core values; leveraging our data analytics, emerging technology, operating execution, strategic sourcing, vertical integration and large-scale asset development expertise to drive cost and capital efficiencies; further enhancing well performance, optimizing well costs and reducing base production declines; and growing margins and securing flow assurance through commercial and marketing arrangements.
•Capturing the Tangible Benefits of Scale. We strive to enhance our enterprise returns by leveraging the scale gained from our past and future strategic transactions to deliver operating synergies, drive cost savings, expand our economic inventory, lower our enterprise risk profile, and expand our opportunity set and optionality.
We remain committed to achieving these objectives while maintaining our commitment to being environmentally conscious and proactive and to using best practices in social stewardship and corporate governance. We believe that we and our industry will continue to face challenges due to evolving environmental standards and expectations of both regulators and investors, the uncertainty of natural gas, oil and NGL prices in the United States, changes in laws, regulations and investor sentiment, and other key factors described above under “Risk Factors.” As such, we intend to protect our financial strength by reducing our debt and by maintaining a derivative program designed to mitigate our exposure to commodity price volatility. RESULTS OF OPERATIONS
The following discussion of our results of operations for our segments is presented before intersegment eliminations. We evaluate our segments as if they were stand-alone operations and accordingly discuss their results prior to any intersegment eliminations. Interest expense, gain (loss) on derivatives, gain (loss) on early extinguishment of debt and income taxes are discussed on a consolidated basis.
We have applied the Securities and Exchange Commission’s FAST Act Modernization and Simplification of Regulation S-K, which limits the discussion to the two most recent fiscal years. This discussion and analysis deals with comparisons of material changes in the consolidated financial statements for fiscal year 2023 and fiscal year 2022. For the comparison of fiscal year 2022 and fiscal year 2021, see “Management's Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of our 2022 Annual Report on Form 10-K, filed with the Securities and Exchange Commission on February 23, 2023.
E&P | | | | | | | | | | | | | | |
| For the years ended December 31, | |
| (in millions) | 2023 | | 2022 | |
| Revenues | $ | 4,109 | | (1) | $ | 10,577 | | (1) |
| Operating costs and expenses | 5,170 | | (2) | 3,324 | | (3) |
| Operating income (loss) | $ | (1,061) | | | $ | 7,253 | | |
| | | | |
| Gain (loss) on derivatives, settled | $ | 345 | | | $ | (5,283) | |
|
(1)Includes a $3 million loss related to gas balancing for the years ended December 31, 2023 and 2022.
(2)Includes $1,710 million of non-cash full-cost ceiling test impairments for the year ended December 31, 2023
(3)Includes $27 million in Merger-related expenses for the year ended December 31, 2022.
Operating Income
•E&P segment operating loss for the year ended December 31, 2023 was $1,061 million compared to operating income of $7,253 million for the year ended December 31, 2022. Excluding $1,710 million of non-cash full cost ceiling test impairments recorded in 2023, our E&P segment operating income decreased $6,604 million from the year ended December 31, 2022 to the year ended December 31, 2023. This decrease is primarily due to lower margins associated with decreased commodity pricing.
Revenues
The following illustrate the effects on sales revenues associated with changes in commodity prices and production volumes:
| | | | | | | | | | | | | | | | | | | | | | | |
| For the years ended December 31, |
| (in millions except percentages) | Natural
Gas | | Oil | | NGLs | | Total |
2022 sales revenues (1) | $ | 9,100 | | | $ | 434 | | | $ | 1,046 | | | $ | 10,580 | |
| Changes associated with prices | (5,574) | | | (113) | | | (427) | | | (6,114) | |
| Changes associated with production volumes | (490) | | | 53 | | | 83 | | | (354) | |
2023 sales revenues (1) | $ | 3,036 | | | $ | 374 | | | $ | 702 | | | $ | 4,112 | |
| Decrease from 2022 | (67) | % | | (14) | % | | (33) | % | | (61) | % |
(1)Excludes $3 million in other operating revenues for the years ended December 31, 2023 and December 31, 2022, primarily related to gas balancing losses.
Production Volumes | | | | | | | | | | | | | | | | | |
| For the years ended December 31, |
| | | | | Increase/(Decrease) |
| 2023 | | 2022 | |
Natural Gas (Bcf) | | | | | |
| Appalachia | 803 | | | 841 | | | (5)% |
| Haynesville | 635 | | | 679 | | | (6)% |
|
| Total | 1,438 | | | 1,520 | | | (5)% |
| | | | | |
Oil (MBbls) | | | | | |
| Appalachia | 5,568 | | | 4,967 | | | 12% |
| Haynesville | 30 | | | 20 | | | 50% |
| Other | 4 | | | 6 | | | (33)% |
| Total | 5,602 | | | 4,993 | | | 12% |
| | | | | |
NGL (MBbls) | | | | | |
| Appalachia | 32,848 | | | 30,445 | | | 8% |
|
| Other | 11 | | | 1 | | | 1,000% |
| Total | 32,859 | | | 30,446 | | | 8% |
| | | | | |
Production volumes by area (Bcfe): | | | | | |
| Appalachia | 1,034 | | | 1,054 | | | (2)% |
| Haynesville | 635 | | | 679 | | | (6)% |
|
| Total | 1,669 | | | 1,733 | | | (4)% |
| | | | | |
Total Production by Formation (Bcfe) | | | | | |
| Marcellus Shale | 917 | | | 891 | | | 3% |
| Utica Shale | 117 | | | 166 | | | (30)% |
| Haynesville Shale | 374 | | | 411 | | | (9)% |
| Bossier Shale | 261 | | | 262 | | | —% |
| Other | — | | | 3 | | | (100)% |
| Total | 1,669 | | | 1,733 | | | (4)% |
| | | | | |
| Production percentage: | | | | | |
| Natural gas | 86 | % | | 88 | % | | |
| Oil | 2 | % | | 2 | % | | |
| NGL | 12 | % | | 10 | % | | |
•Production volumes for our E&P segment decreased 64 Bcfe for the year ended December 31, 2023, compared to the same period in 2022, resulting from our moderation of activity related to the decrease in near-term natural gas prices and the impact of inflation
•Oil and NGL production increased 12% and 8%, respectively, for the year ended December 31, 2023, compared to 2022, primarily due to a higher capital allocation of capital investment to liquids-rich areas.
Commodity Prices
The price we expect to receive for our production is a critical factor in determining the capital investments we make to develop our properties. Commodity prices fluctuate due to a variety of factors we can neither control nor predict, including increased supplies of natural gas, oil or NGLs due to greater exploration and development activities, weather conditions, political and economic events such as the response to a pandemic, and competition from other energy sources. These factors impact supply and demand, which in turn determine the sales prices for our production. In addition to these factors, the prices we realize for our production are affected by our derivative activities as well as locational differences in market prices, including basis differentials. We will continue to evaluate the commodity price environments and adjust the pace of our activity in order to maintain appropriate liquidity and financial flexibility.
| | | | | | | | | | | | | | | | | | | | |
| | For the years ended December 31, |
| | 2023 | | 2022 | | Increase/
(Decrease) |
| Natural Gas Price: | | | | | | |
NYMEX Henry Hub Price ($/MMBtu) (1) | | $ | 2.74 | | | $ | 6.64 | | | (59)% |
Discount to NYMEX (2) | | (0.63) | | | (0.66) | | | (5)% |
Average realized gas price, excluding derivatives ($/Mcf) | | $ | 2.11 | | | $ | 5.98 | | | (65)% |
Gain on settled financial basis derivatives ($/Mcf) | | 0.03 | | | 0.08 | | | |
Gain/(loss) on settled commodity derivatives ($/Mcf) | | 0.22 | | | (3.27) | | | |
Average realized gas price, including derivatives ($/Mcf) | | $ | 2.36 | | | $ | 2.79 | | | (15)% |
| | | | | | |
| Oil Price: | | | | | | |
WTI oil price ($/Bbl) (3) | | $ | 77.62 | | | $ | 94.23 | | | (18)% |
Discount to WTI (4) | | (10.78) | | | (7.28) | | | 48% |
Average realized oil price, excluding derivatives ($/Bbl) | | $ | 66.84 | | | $ | 86.95 | | | (23)% |
Loss on settled derivatives ($/Bbl) | | (9.63) | | | (36.12) | | | |
Average realized oil price, including derivatives ($/Bbl) | | $ | 57.21 | | | $ | 50.83 | | | 13% |
| | | | | | |
| NGL Price: | | | | | | |
Average realized NGL price, excluding derivatives ($/Bbl) | | $ | 21.38 | | | $ | 34.35 | | | (38)% |
Gain/(loss) on settled derivatives ($/Bbl) | | 1.08 | | | (7.83) | | | |
Average realized NGL price, including derivatives ($/Bbl) | | $ | 22.46 | | | $ | 26.52 | | | (15)% |
| Percentage of WTI, excluding derivatives | | 28 | % | | 36 | % | | |
| | | | | | |
| Total Weighted Average Realized Price: | | | | | | |
Excluding derivatives ($/Mcfe) | | $ | 2.46 | | | $ | 6.10 | | | (60)% |
Including derivatives ($/Mcfe) | | $ | 2.67 | | | $ | 3.06 | | | (13)% |
(1)Based on last day settlement prices from monthly futures contracts.
(2)This discount includes a basis differential, a heating content adjustment, physical basis sales, third-party transportation charges and fuel charges, and excludes financial basis hedges.
(3)Based on the average daily settlement price of the nearby month futures contract over the period.
(4)This discount primarily includes location and quality adjustments.
We receive a sales price for our natural gas at a discount to average monthly NYMEX settlement prices based on heating content of the gas, locational basis differentials and transportation and fuel charges. Additionally, we receive a sales price for our oil and NGLs at a difference to average monthly West Texas Intermediate settlement and Mont Belvieu NGL composite prices, respectively, due to a number of factors including product quality, composition and types of NGLs sold, locational basis differentials and transportation and fuel charges.
We regularly enter into various derivatives and other financial arrangements with respect to a portion of our projected natural gas, oil and NGL production in order to ensure certain desired levels of cash flow and to minimize the impact of price fluctuations, including fluctuations in locational market differentials. We refer you to Item 7A, Quantitative and Qualitative Disclosures about Market Risk, of this Annual Report, Note 6 to the consolidated financial statements included in this Annual Report, and the risk factor “Our commodity price risk management and measurement systems and economic hedging activities might not be effective and could increase the volatility of our results” included in Item 1A in this Annual Report for additional discussion about our derivatives and risk management activities.
The tables below present the amount of our future natural gas production in which the impact of basis volatility has been limited through derivatives and physical sales arrangements as of December 31, 2023:
| | | | | | | | | | | |
| Volume (Bcf) | | Basis Differential |
| Basis Swaps – Natural Gas | | | |
| 2024 | 82 | | | $ | (0.72) | |
| 2025 | 9 | | | (0.64) | |
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| Total | 91 | | | |
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Physical NYMEX Sales Arrangements – Natural Gas (1) | | | |
| 2024 | 813 | | | $ | (0.19) | |
| 2025 | 575 | | | (0.12) | |
| 2026 | 418 | | | (0.06) | |
| 2027 | 340 | | | (0.03) | |
| 2028 | 302 | | | (0.02) | |
| 2029 | 252 | | | (0.01) | |
| 2030 | 105 | | | (0.01) | |
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(1)Includes call options expiring from 2024 through 2026.
We refer you to Note 6 of the consolidated financial statements included in this Annual Report for additional details about our derivative instruments. Operating Costs and Expenses
| | | | | | | | | | | | | | | | | |
| For the years ended December 31, |
| (in millions except percentages) | 2023 | | 2022 | | Increase/(Decrease) |
| Lease operating expenses | $ | 1,751 | | | $ | 1,706 | | | 3% |
| General & administrative expenses | 164 | | | 154 | | | 6% |
| Merger-related expenses | — | | | 27 | | | (100)% |
|
| Taxes, other than income taxes | 243 | | | 268 | | | (9)% |
| Full cost pool amortization | 1,287 | | | 1,154 | | | 12% |
| Non-full cost pool DD&A | 15 | | | 15 | | | 0% |
| Impairments | 1,710 | | | — | | | 100% |
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| Total operating costs | $ | 5,170 | | | $ | 3,324 | | | 56% |
| | | | | | | | | | | | | | | | | |
| For the years ended December 31, |
| Average unit costs per Mcfe: | 2023 | | 2022 | | Increase/(Decrease) |
Lease operating expenses (1) | $ | 1.05 | | | $ | 0.98 | | | 7% |
| General & administrative expenses | $ | 0.10 | | | $ | 0.09 | | (2) | 11% |
| Taxes, other than income taxes | $ | 0.15 | | | $ | 0.15 | | | —% |
| Full cost pool amortization | $ | 0.77 | | | $ | 0.67 | | | 15% |
(1)Includes post-production costs such as gathering, processing, fractionation and compression.
(2)Excludes $27 million in merger-related expenses related to the Indigo and GEPH Mergers for the year ended December 31, 2022.
Lease Operating Expenses
•Lease operating expenses per Mcfe increased $0.07 for the year ended December 31, 2023, compared to 2022, primarily due to the impacts of inflation and lower production volumes.
General and Administrative Expenses
•General and administrative expenses increased $0.01 per Mcfe for the year ended December 31, 2023, compared to 2022, primarily due to costs associated with the development of our enterprise resource technology and lower production volumes.
Merger-Related Expenses
•The table below presents the charges incurred for our merger-related activities for the year ended December 31, 2022:
| | | | | | | | | | | | | | | | | | | | | |
| For the year ended December 31, 2022 | | | | |
|
| (in millions) | Indigo
Merger | | GEPH
Merger | | Total | | | | |
| Transition Services | $ | — | | | $ | 18 | | | $ | 18 | | | | | |
| Contract buyouts, terminations and transfers | 1 | | | 2 | | | 3 | | | | | |
| Due diligence and environmental | 1 | | | 1 | | | 2 | | | | | |
| Other | — | | | 2 | | | 2 | | | | | |
| Professional fees (bank, legal, consulting) | — | | | 1 | | | 1 | | | | | |
| Employee-related | — | | | 1 | | | 1 | | | | | |
| | | | | | | | | |
| Total merger-related expenses | $ | 2 | | | $ | 25 | | | $ | 27 | | | | | |
We did not incur any merger-related costs for the year ended December 31, 2023. We refer you to Note 2 of the consolidated financial statements included in this Annual Report for additional details about the Mergers. Taxes, Other than Income Taxes
•On a per Mcfe basis, taxes, other than income taxes may vary from period to period due to changes in ad valorem and severance taxes that result from the mix of our production volumes, fluctuations in commodity prices and changes in the tax rates enacted by the respective states we operate in.
•Taxes, other than income taxes, per Mcfe remained flat for the year ended December 31, 2023, compared to the same period in 2022, primarily due to increased ad valorem taxes offset by the impact of lower commodity pricing on our severance taxes in West Virginia, which are calculated as a fixed percentage of the revenue net of allowable production expenses.
Full Cost Pool Amortization
•Our full cost pool amortization rate increased $0.10 per Mcfe for the year ended December 31, 2023, as compared to 2022 as a result of increases in development costs as a result of inflation.
•The amortization rate is impacted by the timing and amount of reserve additions and the future development costs associated with those additions, revisions of previous reserve estimates due to both price and well performance, write-downs that result from non-cash full cost ceiling impairments, proceeds from the sale of properties that reduce the full cost pool, and the levels of costs subject to amortization. We cannot predict our future full cost pool amortization rate with accuracy due to the variability of each of the factors discussed above, as well as other factors, including but not limited to the uncertainty of the amount of future reserve changes.
•Unevaluated costs excluded from amortization were $2,075 million at December 31, 2023 compared to $2,217 million at December 31, 2022. The unevaluated costs excluded from amortization decreased by $142 million, as compared to 2022, as the evaluation of previously unevaluated properties totaling $365 million was partially offset by $223 million of unevaluated capital invested during the period.
Impairments
•We recognized $1,710 million in non-cash full cost ceiling test impairments for the year ended December 31, 2023 primarily due to decreased commodity pricing over the prior 12 months.
Marketing
| | | | | | | | | | | | | | | | | |
| For the years ended December 31, |
| (in millions except percentages) | 2023 | | 2022 | | Increase/(Decrease) |
| Marketing revenues | $ | 6,277 | | | $ | 14,521 | | | (57)% |
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| Marketing purchases | 6,161 | | | 14,398 | | | (57)% |
| Operating costs and expenses | 24 | | | 22 | | | 9% |
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| Operating income | $ | 92 | | | $ | 101 | | | (9)% |
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Volumes marketed (Bcfe) | 2,303 | | | 2,266 | | | 2% |
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We refer you to Note 6 to the consolidated financial statements included in this Annual Report for additional details about our gain (loss) on derivatives. Gain (Loss) on Early Extinguishment of Debt
•For the year ended December 31, 2023, we redeemed all of the outstanding 7.75% Senior Notes due 2027 at a redemption price equal to 103.875% of the principal amount thereof plus accrued and unpaid interest of $13 million for a total payment of $450 million. We recognized a $19 million loss on the extinguishment of debt, which included the write off of $3 million in related unamortized debt discounts and debt issuance costs.
•For the year ended December 31, 2022, we retired $816 million of long term debt at a cost of $822 million and recorded a loss on early extinguishment of debt of $14 million, which included $6 million of premiums and fees and the write off of $8 million in related unamortized debt discounts and issuance costs. The debt retirements included the repurchase of $46 million of our 8.375% Senior Notes due 2028, $19 million of our 7.75% Senior Notes due 2027 and the full redemption of $201 million of our 4.10% Senior Notes due 2022 and $550 million of our Term Loan.
Income Taxes
| | | | | | | | | | | |
| For the years ended December 31, |
| (in millions except percentages) | 2023 | | 2022 |
| Income tax expense (benefit) | $ | (257) | | | $ | 51 | |
| Effective tax rate | (20) | % | | 3 | % |
•Our effective tax rate was approximately (20)% for the year ended December 31, 2023 primarily as a result of the release of the valuation allowances against our U.S. deferred tax assets. A valuation allowance for deferred tax assets, including NOLs, is recognized when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized. To assess that likelihood, we used estimates and judgment regarding future taxable income and considered the tax consequences in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include current financial position, results of operations, both actual and forecasted, the reversal of deferred tax liabilities and tax planning strategies as well as the current and forecasted business economics of the oil and gas industry.
•For the year ended December 31, 2022, we maintained a full valuation allowance against our deferred tax assets based on our conclusion, considering all available evidence (both positive and negative), that it was more likely than not that the deferred tax assets would not be realized. A significant item of objective negative evidence considered was the cumulative pre-tax loss incurred over the three-year period ended December 31, 2022, primarily due to impairments of proved oil and gas properties recognized in 2020. We sustained a three-year cumulative level of profitability as of the first quarter of 2023 which was maintained through the end of 2023. Based on this factor and other positive evidence such as forecasted income, we concluded that $512 million of our federal and state deferred tax assets were more likely than not to be realized and released this portion of the valuation allowance in 2023. Accordingly, for the year ended December 31, 2023, we recognized $269 million of deferred income tax expense related to our tax provision which was offset by $526 million of tax benefit, including $14 million that was reclassified from OCI, attributable to the release of the valuation allowance. We expect to keep a valuation allowance of $52 million related to NOLs in jurisdictions in which we no longer operate and against a portion of our federal and state deferred tax assets such as capital losses and interest carryovers, which may expire before being fully utilized due to the application of the limitations under Section 382 and the ordering in which such attributes may be applied.
•Due to the issuance of common stock associated with the Indigo Merger, as discussed in Note 2 to the consolidated financial statements to this Annual Report, we incurred a cumulative ownership change and as such, our net operating losses (“NOLs”) prior to the acquisition are subject to an annual limitation under Internal Revenue Code Section 382 of approximately $48 million. The ownership changes and resulting annual limitation will result in the expiration of NOLs or other tax attributes otherwise available. At December 31, 2023, we had approximately $4 billion of federal NOL carryovers, of which approximately $3 billion have an expiration date between 2035 and 2037 and $1 billion have an indefinite carryforward life. We currently estimate that approximately $2 billion of these federal NOLs will expire before they are able to be used and accordingly, no value has been ascribed to these NOLs on our balance sheet. If a subsequent ownership change were to occur as a result of future transactions in our common stock, our use of remaining U.S. tax attributes may be further limited. The Inflation Reduction Act of 2022 (the “IRA”) was enacted on August 16, 2022 and may impact how the U.S. taxes certain large corporations. In addition to other provisions, the IRA imposes a 15% corporate alternative minimum tax (“CAMT”) on the “adjusted financial statement income” of certain large corporations (generally, corporations reporting at least $1 billion average adjusted pre-tax net income on their consolidated financial statements) for tax years beginning after December 31, 2022. This alternative minimum tax requires complex computations to be performed that were not previously required in U.S. tax law, significant judgments to be made in interpretation of the provisions of the IRA, significant estimates in calculations, and the preparation and analysis of information not previously relevant or regularly produced. The U.S. Treasury Department, the Internal Revenue Service, and other standard-setting bodies are expected to issue guidance on how the alternative minimum tax provisions of the IRA will be applied or otherwise administered that may differ from our interpretations. As we complete our analysis of the IRA, collect and prepare necessary data, and interpret any additional guidance, we may make adjustments to provisional amounts that we have recorded that may materially impact our provision for income taxes in the period in which adjustments are made. CAMT did not have any impact on the Company’s consolidated financial statements during 2023. Additionally, the IRA created a U.S. federal 1% excise tax on certain repurchases of stock by publicly traded U.S. domestic corporations occurring on or after January 1, 2023. Because we did not repurchase any shares during 2023, we were not affected by the stock buyback tax in 2023. We will continue to monitor updates to the IRA and the impact it will have on our consolidated financial statements.
We refer you to Note 11 to the consolidated financial statements included in this Annual Report for additional discussion about our income taxes. LIQUIDITY AND CAPITAL RESOURCES
We depend primarily on funds generated from our operations, our 2022 credit facility, our cash and cash equivalents balance and our access to capital markets as our primary sources of liquidity. On April 8, 2022, we restated our 2018 credit facility and extended the maturity through April 2027 (the “2022 credit facility”). In connection with entering into our 2022 credit facility, the banks participating in our 2022 credit facility increased our borrowing base to $3.5 billion and agreed to provide five-year revolving commitments of $2.0 billion (the “Five-Year Tranche”) and agreed to updated terms that provide the ability to convert
our secured credit facility to an unsecured credit facility if we are able to achieve investment grade status, as deemed by the relevant rating agencies.
On October 4, 2023, our borrowing base and elected aggregate commitments were reaffirmed at $3.5 billion and our Five-Year Tranche was reaffirmed at $2.0 billion. At December 31, 2023, we had approximately $1.8 billion of total available liquidity, which exceeds our currently modeled needs as we remain committed to our strategy of capital discipline.
Effective August 4, 2022, we elected to temporarily increase commitments under the 2022 credit facility by $500 million (the “Short-Term Tranche”) as a resource to manage temporary and potentially higher hedge-related working capital movements. We had no borrowings under the Short-Term Tranche which expired on April 30, 2023 and was not renewed. Additionally, in early 2023, we aligned the settlement dates of go-forward natural gas hedge initiations with the dates of the underlying sales receipts to mitigate future temporary hedge-related working capital needs.
In December 2021, in conjunction with the GEPH Merger we raised $550 million in term loan financing (the “Term Loan”) to partially fund the GEPH Merger, with no impact to our liquidity. On December 30, 2022, the Company repaid in full all outstanding indebtedness under the Term Loan. The payoff amount included term loans in the principal amount of approximately $546 million, plus accrued but unpaid interest, fees, and expenses, which satisfied all of the Company’s indebtedness obligations thereunder. In connection with the repayment of such outstanding indebtedness obligations, all security interests, mortgages, liens and encumbrances securing the obligations under the Term Loan, the Term Loan, related loan documents, and all guarantees of such indebtedness obligations were terminated. The Company funded the repayment of the obligations under the Term Loan with approximately $305 million in cash on hand and approximately $250 million of borrowings under the Company’s 2022 credit facility.
We refer you to Note 9 to the consolidated financial statements included in this Annual Report and the section below under “Credit Arrangements and Financing Activities” for additional discussion of our 2022 credit facility and related covenant requirements. In June 2022, we announced a share repurchase program which authorized us to repurchase up to $1 billion of our outstanding common stock beginning June 21, 2022 and continuing through and including December 31, 2023. During 2022, we repurchased approximately 17.3 million shares of our outstanding common stock at an average price of $7.24 per share for a total cost of approximately $125 million. We did not repurchase any shares during 2023 as we prioritized debt repayment during periods of lower realized commodity prices.
Looking forward, we intend to prioritize the use of any free cash flow to pay down our debt in order to progress toward our debt target of $3.5 billion to $3.0 billion or lower and our leverage target of 1.5x to 1.0x.
Our cash flow from operating activities is highly dependent upon our ability to sell and the sales prices that we receive for our natural gas and liquids production. Natural gas, oil and NGL prices are subject to wide fluctuations and are driven by market supply and demand, which is impacted by many factors. See "Market Conditions and Commodity Prices" in the Overview section of Item 7 in Part II for additional discussion about current and potential future market conditions. The sales price we receive for our production is also influenced by our commodity derivative program. Our derivative contracts allow us to ensure a certain level of cash flow to fund our operations. Although we are continually adding additional derivative positions for portions of our expected 2024, 2025 and 2026 production, there can be no assurance that we will be able to add derivative positions to cover the remainder of our expected production at favorable prices. See “Risk Factors” in Item 1A, “Quantitative and Qualitative Disclosures about Market Risk” in Item 7A and Note 6 in the consolidated financial statements included in this Annual Report for further details. Our commodity hedging activities are subject to the credit risk of our counterparties being financially unable to settle the transaction. We actively monitor the credit status of our counterparties, performing both quantitative and qualitative assessments based on their credit ratings and credit default swap rates where applicable, and to date have not had any credit defaults associated with our transactions. However, any future failures by one or more counterparties could negatively impact our cash flow from operating activities. Additionally, we do not expect the events of early 2023 within the banking industry to have a material impact on our expected results of operations, financial performance, or liquidity. However, if there are issues in the wider financial system and if other financial institutions fail, our business, liquidity and financial condition could be materially affected, including as a result of impacts of any such issues or failures on our counterparties.
Our short-term cash flows are also dependent on the timely collection of receivables from our customers and joint interest owners. We actively manage this risk through credit management activities and, through the date of this filing, have not experienced any significant write-offs for non-collectable amounts. However, any sustained inaccessibility of credit by our customers and joint interest owners could adversely impact our cash flows.
Due to these factors, we are unable to forecast with certainty our future level of cash flow from operations. Accordingly, we expect to adjust our discretionary uses of cash depending upon available cash flow. Further, we may from time to time seek to retire, rearrange or amend some or all of our outstanding debt or debt agreements through cash purchases, and/or exchanges, open market purchases, privately negotiated transactions, tender offers or otherwise. Such transactions, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
Credit Arrangements and Financing Activities
In April 2022, we entered into an amended and restated credit agreement that replaced the 2018 credit facility (the "2022 credit facility") that, as amended, has a maturity date of April 2027. As of December 31, 2023, the 2022 credit facility had an aggregate maximum revolving credit amount and borrowing base of $3.5 billion and elected commitments of $2.0 billion.
The borrowing base is subject to redetermination at least twice a year, which typically occurs in April and October, and is subject to change based primarily on drilling results, commodity prices, our future derivative position, the level of capital investment and operating costs. The 2022 credit facility is secured by substantially all of our assets and our subsidiaries’ assets (taken as a whole). The permitted lien provisions in the senior note indentures currently limit liens securing indebtedness to the greater of $2.0 billion or 25% of adjusted consolidated net tangible assets. The 2022 credit facility contains the ability to utilize SOFR index rates for purposes of calculating interest expense.
The 2022 credit facility has certain financial covenant requirements but provides certain fall away features should we receive an Investment Grade Rating (defined as an index debt rating of BBB- or higher with S&P, Baa3 or higher with Moody’s, or BBB- or higher with Fitch) and meet other criteria in the future. We refer you to Note 9 to the consolidated financial statements included in this Annual Report for additional discussion of our 2022 credit facility. As of December 31, 2023, we were in compliance with all of the applicable covenants contained in the credit agreement governing our 2022 credit facility. Our ability to comply with financial covenants in future periods depends, among other things, on the success of our development program and upon other factors beyond our control, such as the market demand and prices for natural gas and liquids. We refer you to Note 9 of the consolidated financial statements included in this Annual Report for additional discussion of the covenant requirements of our 2022 credit facility. As of December 31, 2023, we had $220 million of borrowings on our 2022 credit facility and no outstanding letters of credit. We currently do not anticipate being required to supply a materially greater amount of letters of credit under our existing contracts. We refer you to Note 9 to the consolidated financial statements included in this Annual Report for additional discussion of our 2022 credit facility. The credit status of the financial institutions participating in our 2022 credit facility could adversely impact our ability to borrow funds under the 2022 credit facility. Although we believe all of the lenders under the facility have the ability to provide funds, we cannot predict whether each will be able to meet their obligation to us. We refer you to Note 9 to the consolidated financial statements included in this Annual Report for additional discussion of our 2022 credit facility. In contemplation of the GEPH Merger, on December 22, 2021, we entered into a term loan credit agreement with a group of lenders that provided for a $550 million secured term loan facility. On December 30, 2022, we repaid in full the remaining principal balance of $546 million and all other outstanding indebtedness under the Term Loan using approximately $305 million of cash on hand and approximately $250 million of borrowings under our 2022 credit facility.
Key financing activities for the years ended December 31, 2023 and 2022 are as follows:
Debt Repurchase
•In February 2023, we redeemed all of the outstanding 7.750% Senior Notes due 2027 at a redemption price equal to 103.875% of the principal amount thereof plus accrued and unpaid interest of $13 million for a total payment of $450 million. We recognized a $19 million loss on the extinguishment of debt, which included the write off of $3 million in related unamortized debt discounts and debt issuance costs. We funded the redemption using approximately $316 million of cash on hand and approximately $134 million of borrowings under our 2022 credit facility.
•In December 2022, we repaid the remaining outstanding principal balance of our Term Loan of $546 million using approximately $305 million in cash on hand and approximately $250 million of borrowings under our 2022 credit facility, and we wrote off the related unamortized debt discounts and issuance costs resulting in a loss on early debt extinguishment of $8 million. As a result of the focused work on refinancing and repayment of our debt in recent years, coupled with the
amendment and restatement of our credit facility on April 8, 2022, we have no debt balances scheduled to become due prior to 2025.
•In May 2022, we repurchased $18 million of our 8.375% Senior Notes due 2028, resulting in a $1 million loss on debt extinguishment.
•In April 2022, we repurchased $4 million of our 7.75% Senior Notes due 2027 and $23 million of our 8.375% Senior Notes due 2028, resulting in a $3 million loss on debt extinguishment.
•In March 2022, we repurchased $15 million of our 7.75% Senior Notes due 2027 and $5 million of our 8.375% Senior Notes due 2028, resulting in a $2 million loss on debt extinguishment.
•In January 2022, we repurchased the remaining outstanding principal balance of $201 million on our 2022 Senior Notes using our credit facility.
At February 20, 2024, we had long-term debt issuer ratings of Ba1 by Moody’s (rating affirmed Ba1 and outlook upgraded to positive on January 11, 2024 in conjunction with the Proposed Merger announcement), BB+ by S&P (rating affirmed BB+ and outlook upgraded to positive on January 18, 2023) and BB+ by Fitch Ratings (rating and positive outlook affirmed on August 16, 2023). Both S&P and Fitch also placed us on Credit / Rating Watch Positive on January 11, 2024 following the Proposed Merger announcement. Effective in January 2022, the interest rate for our 4.95% 2025 Senior Notes (“2025 Notes”) was 5.95%, reflecting a net downgrade in our bond ratings since their issuance. On May 31, 2022, Moody’s upgraded our bond rating to Ba1, which decreased the interest rate on the 2025 Notes from 5.95% to 5.70% for coupon payments paid after July 2022. Any further upgrades or downgrades in our public debt ratings by Moody’s or S&P could decrease or increase our cost of funds, respectively, as our 2025 Notes are subject to ratings driven changes.
Cash Flows
| | | | | | | | | | | |
| For the years ended December 31, |
| (in millions) | 2023 | | 2022 |
| Net cash provided by operating activities | $ | 2,516 | | | $ | 3,154 | |
| Net cash used in investing activities | (2,047) | | | (2,043) | |
| Net cash used in financing activities | (498) | | | (1,089) | |
Cash Flow from Operations
| | | | | | | | | | | |
| For the years ended December 31, |
| (in millions) | 2023 | | 2022 |
| Net cash provided by operating activities | $ | 2,516 | | | $ | 3,154 | |
| Add back (subtract): changes in working capital | (243) | | | (124) | |
| Net cash provided by operating activities, net of changes in working capital | $ | 2,273 | | | $ | 3,030 | |
•Net cash provided by operating activities of $2,516 million decreased 20% from $3,154 million in 2022, primarily due to a $6,114 million decrease resulting from lower commodity prices, a $354 million decrease related to decreased production and a $7 million decrease in our marketing margin. The decreases were partially offset by a $5,628 million increase in our settled derivative position, a $119 million increased impact of working capital, a $56 million decrease in current taxes and a $42 million decrease in interest expense.
•Net cash generated from operating activities, net of changes in working capital, exceeded our capital investments by $142 million and $821 million for the years ended December 31, 2023 and December 31, 2022, respectively.
Cash Flow from Investing Activities
•Total E&P capital investing decreased $74 million for the year ended December 31, 2023, compared to the same period in 2022, due to a $68 million decrease in direct E&P capital investing which was primarily related to decreased activity in 2023 as compared to 2022 and a $6 million decrease in capitalized interest.
•Capitalized interest decreased for the year ended December 31, 2023, as compared to the same period in 2022, primarily due to the evaluation of natural gas and oil properties exceeding investment in unevaluated properties over the past twelve months.
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| For the years ended December 31, |
| (in millions) | 2023 | | 2022 |
| Additions to properties and equipment | $ | 2,170 | | | $ | 2,115 | |
| Adjustments for capital investments: | | | |
| Changes in capital accruals | (44) | | | 88 | |
Other (1) | 5 | | | 6 | |
| Total capital investing | $ | 2,131 | | | $ | 2,209 | |
(1)Includes capitalized non-cash stock-based compensation and costs to retire assets, which are classified as cash used in operating activities.
Capital Investing
| | | | | | | | | | | | | | | | | |
| For the years ended December 31, |
| (in millions except percentages) | 2023 | | 2022 | | Increase/
(Decrease) |
| E&P capital investing | $ | 2,122 | | | $ | 2,196 | | | |
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Other capital investing (1) | 9 | | | 13 | | | |
| Total capital investing | $ | 2,131 | | | $ | 2,209 | | | (4)% |
(1)Other capital investing relates to the development of our enterprise resource technology and purchases of information technology for the year ended December 31, 2023 and purchases of information technology and other corporate spending for the year ended December 31, 2022.
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| For the years ended December 31, |
| (in millions) | 2023 | | 2022 |
| E&P Capital Investments by Type: | | | |
| Exploratory and development, including workovers | $ | 1,812 | | | $ | 1,892 | |
| Acquisition of properties | 69 | | | 81 | |
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| Other | 41 | | | 17 | |
| Capitalized interest and expenses | 200 | | | 206 | |
| Total E&P capital investments | $ | 2,122 | | | $ | 2,196 | |
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| E&P Capital Investments by Area | | | |
| Appalachia | $ | 938 | | | $ | 953 | |
| Haynesville | 1,138 | | | 1,229 | |
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Management’s Report on Internal Control Over Financial Reporting
It is the responsibility of the management of Southwestern Energy Company to establish and maintain adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act). Management has assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2023, utilizing the Committee of Sponsoring Organizations of the Treadway Commission’s Internal Control – Integrated Framework (2013).
Based on this evaluation, management has concluded the Company’s internal control over financial reporting was effective as of December 31, 2023.
The effectiveness of our internal control over financial reporting as of December 31, 2023 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report which appears herein.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of Southwestern Energy Company
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Southwestern Energy Company and its subsidiaries (the “Company”) as of December 31, 2023 and 2022, and the related consolidated statements of operations, of comprehensive income (loss), of changes in equity and of cash flows for each of the three years in the period ended December 31, 2023, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control – Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting 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 audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated 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 consolidated 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 consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that
(i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
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.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
The Impact of Proved Natural Gas, Oil and NGL Reserves on Natural Gas and Oil Properties
As described in Note 1 to the consolidated financial statements, the Company’s consolidated natural gas and oil properties balance was $37,772 million as of December 31, 2023, and depreciation, depletion and amortization expense for the year ended December 31, 2023 was $1,307 million. The Company utilizes the full cost method of accounting for its natural gas and oil properties. Under this method, all capitalized costs are amortized over the estimated lives of the properties using the unit-of-production method based on proved natural gas, oil and natural gas liquids (NGL) reserves. These capitalized costs are subject to a ceiling test that limits such pooled costs, net of applicable deferred taxes, to the aggregate of the present value of future net revenues attributable to proved natural gas, oil and NGL reserves discounted at 10%. For the year ended December 31, 2023, pre-tax impairment charges of $1,710 million were recognized. As disclosed by management, proved natural gas, oil and NGL reserves are a major component of the full cost ceiling test. Estimates of reserves require extensive judgments of available reservoir geologic, geophysical and engineering data as well as certain economic assumptions such as commodity pricing and the costs that will be incurred in developing and producing reserves. The estimates of natural gas, oil and NGL reserves have been developed by specialists, specifically reservoir engineers, and audited by independent petroleum engineers (together referred to as “specialists”).
The principal considerations for our determination that performing procedures relating to the impact of proved natural gas, oil and NGL reserves on natural gas and oil properties, is a critical audit matter are (i) the significant judgment by management, including the use of management’s specialists, when developing the estimate of proved natural gas, oil and NGL reserves and (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence related to the data, methods, and assumptions used by management and its specialists in developing the estimates of proved natural gas, oil and NGL reserves applied to the full cost ceiling test.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s estimates of proved natural gas, oil and NGL reserves and the full cost ceiling test calculation. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the estimates of proved natural gas, oil and NGL reserves applied in the full cost ceiling test. As a basis for using this work, specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. These procedures also included evaluating of the methods and assumptions used by specialists, testing of the completeness and accuracy of the data related to commodity pricing, future development costs and historical production used by the specialists, and evaluating the specialists’ findings.
/s/
February 22, 2024
We have served as the Company’s auditor since 2002.
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS | | | | | | | | | | | | | | | | | |
| For the years ended December 31, |
| (in millions, except share/per share amounts) | 2023 | | 2022 | | 2021 |
| Operating Revenues: | | | | | |
| Gas sales | $ | | | | $ | | | | $ | | |
| Oil sales | | | | | | | | |
| NGL sales | | | | | | | | |
| Marketing | | | | | | | | |
|
| Other | () | | | () | | | | |
| | | | | | | | |
| Operating Costs and Expenses: | | | | | |
| Marketing purchases | | | | | | | | |
| Operating expenses | | | | | | | | |
| General and administrative expenses | | | | | | | | |
| Merger-related expenses | | | | | | | | |
| Restructuring charges | | | | | | | | |
|
| Depreciation, depletion and amortization | | | | | | | | |
| Impairments | | | | | | | | |
| Taxes, other than income taxes | | | | | | | | |
| | | | | | | | |
| Operating Income (Loss) | () | | | | | | | |
| Interest Expense: | | | | | |
| Interest on debt | | | | | | | | |
| Other interest charges | | | | | | | | |
| Interest capitalized | () | | | () | | | () | |
| | | | | | | | |
| | | | | |
| Gain (Loss) on Derivatives | | | | () | | | () | |
| Loss on Early Extinguishment of Debt | () | | | () | | | () | |
| Other Income, Net | | | | | | | | |
| | | | | |
| Income (Loss) Before Income Taxes | | | | | | | () | |
| Provision (Benefit) for Income Taxes | | | | | |
| Current | () | | | | | | | |
| Deferred | () | | | | | | | |
| () | | | | | | | |
| Net Income (Loss) | $ | | | | $ | | | | $ | () | |
|
|
|
| | | | | |
| Earnings (Loss) Per Common Share | | | | | |
| Basic | $ | | | | $ | | | | $ | () | |
| Diluted | $ | | | | $ | | | | $ | () | |
| | | | | |
| Weighted Average Common Shares Outstanding: | | | | | |
| Basic | | | | | | | | |
| Diluted | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements.
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) | | | | | | | | | | | | | | | | | |
| For the years ended December 31, |
| (in millions) | 2023 | | 2022 | | 2021 |
| Net income (loss) | $ | | | | $ | | | | $ | () | |
| | | | | |
| Change in value of pension and other postretirement liabilities: | | | | | |
Amortization of prior service cost and net (gain) loss, including (gain) loss on settlements and curtailments included in net periodic pension cost (1) | () | | | () | | | | |
Net actuarial gain incurred in period (2) | | | | | | | | |
| Tax valuation allowance release impact on pension settlements | () | | | | | | | |
| Total change in value of pension and postretirement liabilities | () | | | | | | | |
| |
| |
| |
| Comprehensive income (loss) | $ | | | | $ | | | | $ | () | |
(1)
(2)
The accompanying notes are an integral part of these consolidated financial statements.
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS | | | | | | | | | | | |
| December 31,
2023 | | December 31,
2022 |
| ASSETS | (in millions, except share amounts) |
| Current assets: | | | |
| Cash and cash equivalents | $ | | | | $ | | |
| Accounts receivable, net | | | | | |
| Derivative assets | | | | | |
| Other current assets | | | | | |
| Total current assets | | | | | |
Natural gas and oil properties, using the full cost method, including $ million as of December 31, 2023 and $ million as of December 31, 2022 excluded from amortization | | | | | |
| Other | | | | | |
| Less: Accumulated depreciation, depletion and amortization | () | | | () | |
| Total property and equipment, net | | | | | |
| Operating lease assets | | | | | |
| Long-term derivative assets | | | | | |
| Deferred tax assets | | | | | |
| Other long-term assets | | | | | |
| Total long-term assets | | | | | |
| TOTAL ASSETS | $ | | | | $ | | |
| LIABILITIES AND EQUITY | | | |
| Current liabilities: | | | |
|
| Accounts payable | $ | | | | $ | | |
| Taxes payable | | | | | |
| Interest payable | | | | | |
| Derivative liabilities | | | | | |
| Current operating lease liabilities | | | | | |
| Other current liabilities | | | | | |
| Total current liabilities | | | | | |
| Long-term debt | | | | | |
| Long-term operating lease liabilities | | | | | |
| Long-term derivative liabilities | | | | | |
|
| Other long-term liabilities | | | | | |
| Total long-term liabilities | | | | | |
Commitments and contingencies (Note 10) | | | |
| Equity: | | | |
Common stock, $ par value; shares authorized; issued shares as of December 31, 2023 and as of December 31, 2022 | | | | | |
| Additional paid-in capital | | | | | |
| Accumulated deficit | () | | | () | |
| Accumulated other comprehensive income (loss) | () | | | | |
Common stock in treasury, shares as of December 31, 2023 and as of December 31, 2022 | () | | | () | |
| Total equity | | | | | |
| TOTAL LIABILITIES AND EQUITY | $ | | | | $ | | |
The accompanying notes are an integral part of these consolidated financial statements.
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS | | | | | | | | | | | | | | | | | |
| For the years ended December 31, |
| (in millions) | 2023 | | 2022 | | 2021 |
| Cash Flows From Operating Activities: | | | | | |
| Net income (loss) | $ | | | | $ | | | | $ | () | |
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | | | |
| Depreciation, depletion and amortization | | | | | | | | |
| Amortization of debt issuance costs | | | | | | | | |
| Impairments | | | | | | | | |
| Deferred income taxes | () | | | | | | | |
| (Gain) loss on derivatives, unsettled | () | | | () | | | | |
| Stock-based compensation | | | | | | | | |
| Loss on early extinguishment of debt | | | | | | | | |
|
|
| Other | | | | | | | () | |
| Changes in assets and liabilities, net of effect of Mergers: | | | | | |
| Accounts receivable | | | | () | | | () | |
| Accounts payable | () | | | | | | | |
| Taxes payable | () | | | | | | () | |
| Interest payable | () | | | | | | | |
| Inventories | () | | | | | | () | |
| Other assets and liabilities | () | | | () | | | () | |
| Net cash provided by operating activities | | | | | | | | |
| | | | | |
| Cash Flows From Investing Activities: | | | | | |
| Capital investments | () | | | () | | | () | |
| Proceeds from sale of property and equipment | | | | | | | | |
| Cash acquired in mergers | | | | | | | | |
| Cash paid in mergers | | | | | | | () | |
|
|
| Net cash used in investing activities | () | | | () | | | () | |
| | | | | |
| Cash Flows From Financing Activities: | | | | | |
| Payments on current portion of long-term debt | | | | () | | | | |
| Payments on long-term debt | () | | | () | | | () | |
| Payments on revolving credit facility | () | | | () | | | () | |
| Borrowings under revolving credit facility | | | | | | | | |
| Change in bank drafts outstanding | () | | | | | | | |
| Repayment of revolving credit facilities associated with Mergers | | | | | | | () | |
|
| Proceeds from exercise of common stock options | | | | | | | | |
| Proceeds from issuance of long-term debt | | | | | | | | |
| Debt issuance and other financing costs | | | | () | | | () | |
|
| Purchase of treasury stock | | | | () | | | | |
|
| Cash paid for tax withholding | () | | | () | | | () | |
|
|
| | — | | | — | | | — | | | — | | | | |
| | | | | | | | | | | | |
| | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | |
| | — | | | — | | | — | | | — | | | | |
| | | | | | | | | | | | |
)
| | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | |
| | — | | | — | | | | | | () | | | () | |
| | | | | | | | | | | | |
)
| | — | | | — | | | — | | | — | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | — | | | — | | | — | | | — | | | — | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | — | | | — | | | — | | | — | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
)| | | | $ | () | | | $ | () | | | | | | $ | () | | | $ | | |
The accompanying notes are an integral part of these consolidated financial statements.
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1)
segments: E&P and Marketing. E&P. Southwestern’s primary business is the development and production of natural gas as well as associated NGLs and oil, with ongoing operations focused on the development of unconventional natural gas and oil reservoirs located in Pennsylvania, West Virginia, Ohio and Louisiana. The Company’s operations in Pennsylvania, West Virginia and Ohio, herein referred to as “Appalachia,” are primarily focused on the Marcellus Shale, the Utica and the Upper Devonian unconventional natural gas and liquids reservoirs. The Company’s operations in Louisiana, herein referred to as “Haynesville,” are primarily focused on the Haynesville and Bossier natural gas reservoirs (“Haynesville and Bossier Shales”). The Company also operates drilling rigs and provides certain oilfield products and services, principally serving the Company's E&P operations through vertical integration.
Marketing. Southwestern’s marketing activities capture opportunities that arise through the marketing and transportation of natural gas, oil and NGLs primarily produced in its E&P operations.
% ownership in a limited partnership that owns and operates a gathering system in Appalachia. Because the Company owns a controlling interest in the partnership, the operating and financial results are consolidated with the Company’s E&P segment results. The minority partner’s share of the partnership activity is reported in retained earnings in the consolidated financial statements. Net income attributable to noncontrolling interest for the years ended December 31, 2023, 2022 and 2021 was insignificant.
% of annual revenues. A default on this account could have a material impact on the Company, but the Company does not believe that there is a material risk of a default. For the year ended December 31, 2022, one purchaser accounted for % of annual revenues. No other purchasers accounted for more than 10% of consolidated revenues. The Company believes that the loss of any one customer would not have an adverse effect on its ability to sell its natural gas, oil and NGL production.
million and $ million in cash and cash equivalents as of December 31, 2023 and 2022, respectively.Certain of the Company’s cash accounts are zero-balance controlled disbursement accounts. The Company presents the outstanding checks written against these zero-balance accounts as a component of accounts payable in the accompanying consolidated balance sheets. Outstanding checks included as a component of accounts payable totaled $ million and $ million as of December 31, 2023 and 2022, respectively.
| | $ | | |
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