# Range Resources Corp: Form 10-K for the period ended Dec 31, 2023 - Company: [Range Resources Corp](/companies/rrc.md) (CIK 315852) - Form: 10-K - Filed: 2024-02-21 - Accepted by EDGAR: Feb 21, 2024, 17:00 ET - Period: 2023-12-31 - Accession: 0000950170-24-018046 - Inline XBRL: yes - Main document: https://www.sec.gov/Archives/edgar/data/315852/000095017024018046/rrc-20231231.htm - All documents and exhibits: https://www.sec.gov/Archives/edgar/data/315852/000095017024018046/ ## Figures reported in this filing Standardized XBRL line items for the period ended 2023-12-31. | Line item | Period | Value | XBRL concept | | --- | --- | ---: | --- | | Revenue | 12 months, 2023-01-01 to 2023-12-31 | $2.55bn | us-gaap:RevenueFromContractWithCustomerExcludingAssessedTax | | Cost of revenue | 12 months, 2023-01-01 to 2023-12-31 | $202.9m | us-gaap:CostOfGoodsAndServicesSold | | Interest expense | 12 months, 2023-01-01 to 2023-12-31 | $124.0m | us-gaap:InterestExpense | | Income tax | 12 months, 2023-01-01 to 2023-12-31 | $229.2m | us-gaap:IncomeTaxExpenseBenefit | | Net income | 12 months, 2023-01-01 to 2023-12-31 | $871.1m | us-gaap:NetIncomeLoss | | Diluted EPS | 12 months, 2023-01-01 to 2023-12-31 | $3.57 | us-gaap:EarningsPerShareDiluted | | Basic EPS | 12 months, 2023-01-01 to 2023-12-31 | $3.61 | us-gaap:EarningsPerShareBasic | | Diluted shares (weighted) | 12 months, 2023-01-01 to 2023-12-31 | 239,837,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding | | Operating cash flow | 12 months, 2023-01-01 to 2023-12-31 | $977.9m | us-gaap:NetCashProvidedByUsedInOperatingActivities | | Dividends paid | 12 months, 2023-01-01 to 2023-12-31 | $77.2m | us-gaap:PaymentsOfDividendsCommonStock | | Cash and equivalents | at 2023-12-31 | $212.0m | us-gaap:CashAndCashEquivalentsAtCarryingValue | | Current assets | at 2023-12-31 | $870.1m | us-gaap:AssetsCurrent | | Total assets | at 2023-12-31 | $7.20bn | us-gaap:Assets | | Current liabilities | at 2023-12-31 | $583.1m | us-gaap:LiabilitiesCurrent | | Total liabilities | at 2023-12-31 | $3.44bn | us-gaap:Liabilities | | Shareholders' equity | at 2023-12-31 | $3.77bn | us-gaap:StockholdersEquity | ## Risk factors As filed, 69,751 characters. While we utilize robust processes and resources to identify and manage risks, we are subject to various risks and uncertainties in the course of our business, some of which are comparable to the risks any business is exposed to and some that are unique to our operations. The following summarizes the known material risks and uncertainties that may adversely affect our business, financial condition or results of operations. When considering making or maintaining an investment in our securities, you should carefully consider the risk factors included below as well as those matters referenced in the section entitled Disclosures Regarding Forward-Looking Statements and other information included and incorporated by reference into this Annual Report on Form 10-K. These risks are not the only risks we face. Our business could also be impacted by additional risks and uncertainties not currently known to us or that we believe not to be material based on the information we have at this time. If any of the events described below as risks actually occur, it could materially harm our business, financial condition or results of operations or impair our ability to implement our business plans or complete development activities as expected. In that case, the market price of our common stock could decline or, if severe enough, the entire value of an investment in our securities could become worthless. ### Economic risks related to our business ***Volatility of natural gas, NGLs and oil prices significantly affects our cash flow and capital resources and could hamper our ability to operate economically.*** Natural gas, NGLs and oil prices are volatile, and a decline in prices adversely affects our profitability and financial condition. As a commodity business, the oil and gas industry is typically cyclical and we expect the volatility to continue. Natural gas prices are likely to affect us more than oil prices because approximately 64% of our proved reserves were natural gas as of December 31, 2023 and, at times in the past, natural gas prices have been low compared to our costs to produce. Natural gas, NGLs and oil prices fluctuate in response to changes in supply and demand, market uncertainty and other factors that are beyond our control. These factors include: - events that impact domestic and foreign supply of, and demand for, natural gas, NGLs and oil, including impacts from global health pandemics and related concerns; - the continued operation of liquefied natural gas (LNG) facilities to supply foreign markets with natural gas and the ability to transport the product to markets due to shipping restrictions or terrorist threats and attacks; - changes in weather patterns and climate, including natural disasters such as hurricanes and tornadoes; - technological advances affecting energy consumption, storage and energy supply; - the production levels of non-OPEC countries, including production levels in the United States’ shale plays; - general economic conditions worldwide; - the price and availability of, and demand for, alternative and competing forms of energy, such as nuclear, hydroelectric, wind and solar; - the level of drilling, completion and production activities by other companies, and variability therein, in response to market conditions; - the effect of worldwide energy conservation efforts; - the ability of the members of OPEC and other exporting nations to agree to production controls; - military, economic and political conditions in natural gas and oil producing regions; - the cost of exploring for, developing, producing, transporting and marketing natural gas, NGLs and oil; and - domestic (federal, state and local) and foreign governmental regulations and taxation, including further legislation requiring, subsidizing or providing tax benefits for the use of alternative energy sources and fuels. The long-term effects of these and other factors on the prices of natural gas, NGLs and oil prices are uncertain. Historical declines in natural gas and NGLs commodity prices have adversely affected our business by: - reducing the amount of natural gas, NGLs and oil that we can economically produce; - reducing our revenues, operating income and cash flows; - reducing the amount of cash flows available for capital expenditures; - increasing the cost of obtaining capital, such as equity and debt financings; and - reducing the standardized measure of discounted future net cash flows relating to natural gas, NGLs and oil. ***If demand for natural gas, NGLs and oil is reduced, the prices we receive for and our ability to market and produce our natural gas, NGLs and oil may be negatively affected.*** Volatility in natural gas, NGLs and oil markets and the price we receive for our production is largely determined by various factors beyond our control. Production from natural gas and oil wells in some geographic areas of the United States has been or could be curtailed for considerable periods of time due to lack of local market demand and transportation and storage capacity. In the recent past, we have temporarily shut-in wells due to low commodity prices and it is possible that some of our wells may be shut-in in the future or sales terms may be less favorable than might otherwise be obtained should demand for our products decrease and/or prices decrease. Competition for markets has been vigorous and there remains uncertainty about prices purchasers will pay or the availability of sufficient storage, all of which could have a material adverse effect on our cash flows, results of operations and financial position. ***We could experience periods of higher costs. These cost increases could reduce our profitability, cash flow and ability to conduct development activities as planned***. We rely on third-party contractors to provide key services and equipment for our operations. Historically, our capital and operating costs have risen during periods of increasing oil, NGLs and gas prices. These cost increases result from a variety of factors beyond our control, such as increases in the cost of electricity, steel and other raw materials that we and our vendors rely upon; increased demand for labor, services and materials as drilling and completions activity increases; and increased taxes. Increased levels of drilling activity in the natural gas and oil industry could lead to increased costs of some drilling equipment, materials and supplies. Such costs may rise faster than increases in our revenue, thereby negatively impacting our profitability, cash flow and ability to conduct development activities as planned and on budget. Based on the cost inflation pressure experienced over the last few years, we continue to undertake actions and implement plans to strengthen our supply chain. Nevertheless, we expect to experience some supply chain constraints and inflationary pressure on our cost structure including steel, fuel and labor, among other items, for the foreseeable future. By continuing to focus on cost control initiatives and actions, which increase our drilling, completion and operating efficiencies, we are able to mitigate some inflationary pressures. ***Our debt obligations may limit our liquidity and financial flexibility***. We are a borrower under fixed rate senior notes and maintain a bank credit facility which had no debt outstanding as of December 31, 2023. Our exploration and development program requires substantial capital resources depending on the level of drilling and the expected cost of services. Existing operations also require ongoing capital expenditures. Increases in our level of debt may: - require us to dedicate a substantial portion of our cash flows from operations to the payment of our indebtedness, reducing the funds available for our operations or return of capital to stockholders; - may make us vulnerable to increases in interest rates; - increase our vulnerability to a downturn in commodity prices or the general economy; - place us at a competitive disadvantage compared to our competitors with lower debt service obligations; - limit our operating flexibility due to financial and other restrictive covenants; and - limit our flexibility to maintain or grow our business and plan for, or react to, changes in our business and the industry in which we operate. Historically, we have funded our capital expenditures through a combination of cash flow from operations, our bank credit facility and debt and equity issuances. We have also engaged in asset monetization transactions. Future cash flows are subject to a number of variables, such as the level of production from existing wells, prices of natural gas, NGLs and oil and our success in developing and producing our reserves. If our access to capital were limited as a result of various factors, which could include a decrease in revenues due to lower natural gas, NGLs and oil prices or decreased production or deterioration of the credit and capital markets, we would have a reduced ability to fund our operations and replace our reserves resulting in stress on our financial flexibility. The amount available for borrowing under our bank credit facility is subject to a borrowing base, which is determined by our lenders, taking into account our estimated proved reserves and is subject to periodic redeterminations based on pricing models determined by the lenders at such time. Declines in natural gas, NGLs and oil prices adversely impact the value of our estimated proved reserves and, in turn, the market values used by our lenders to determine our borrowing base and could result in a determination to lower our borrowing base, reducing our financial flexibility. Disruptions or volatility in the global finance markets may lead to a contraction in credit availability impacting our ability to finance our operations. We benefit from continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to conduct our planned operations, our ability to manage our debt maturities and our flexibility to react to changing economic and business conditions. We are also exposed to some credit risk related to our bank credit facility to the extent that one or more of our lenders experiences liquidity problems and is unable to provide necessary funding to us under our existing revolving line of credit. ***Any failure to meet our debt obligations could harm our business, financial condition and results of operations***. Our earnings and cash flow will fluctuate from year to year due to the variable nature of commodity prices. If our cash flow and capital resources are insufficient to fund our debt obligations, we may be forced to sell assets, seek equity sales or restructure our debt. Our ability to restructure our debt will depend on the condition of the capital markets and our financial condition at such time. Any restructuring of debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our operations and our financial flexibility. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. We receive debt ratings from the major credit rating agencies in the United States. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales and near-term and long-term cash flow relative to debt balances. Liquidity, asset quality, cost structure, product mix (natural gas, NGLs and crude oil) and projected commodity pricing levels are also considered by the rating agencies. A ratings downgrade could adversely impact our ability to access debt markets in the future, increase the cost of future debt and could require us to post letters of credit or other forms of collateral for certain obligations. We cannot provide assurance that our current ratings will remain in effect for any given period of time or that a rating will not be downgraded in the future. ***As a result of cross-default provisions in our borrowing arrangements, we may be unable to satisfy all of our outstanding obligations in the event of a default on our part.*** The terms of our senior indebtedness, including our revolving credit facility, contain cross-default provisions which provide that we will be in default under such agreements in the event of certain defaults under our indentures or other loan agreements. Accordingly, should an event of default above certain thresholds occur under any of those agreements, we face the prospect of being in default under all of our debt agreements, obligated in such instance to satisfy all of our outstanding indebtedness but in all probability unable to satisfy all of our outstanding obligations simultaneously. In such an event, we might not be able to obtain alternative financing or, if we are able to obtain such financing, we might not be able to obtain it on terms acceptable to us, which would negatively affect our ability to continue our business plan, make capital expenditures and finance our operations. ***Derivative transactions may limit our potential gains and involve other risks***. To manage our exposure to commodity price volatility, we currently, and likely will in the future, enter into derivative arrangements, utilizing commodity derivatives ("hedges") with respect to a portion of our future production. Hedges are generally designed to lock in prices for commodities to limit volatility and increase the predictability of cash flow. These hedging transactions can limit our potential gains if natural gas, NGLs and oil prices rise above the price established by the hedge. In addition, derivative transactions may expose us to the risk of financial loss in certain circumstances, including instances in which: - our production is less than expected; - the counterparties to our futures contracts fail to perform on their contract obligations; or - an event materially impacts natural gas, NGLs or oil prices or the relationship between the hedged price index and the natural gas or oil sales prices we receive. We cannot be certain that any derivative transaction we may enter into will adequately protect us from declines in the prices of natural gas, NGLs or oil. Furthermore, where we choose not to engage in derivative transactions in the future, we may be more adversely affected by decreases in natural gas, NGLs or oil prices than our competitors who utilize derivative transactions. Lower natural gas, NGLs and oil prices over a longer term will also negatively impact our ability to enter into derivative contracts at prices that exceed our costs of production. We are exposed to a risk of financial loss if a counterparty fails to perform under a derivative contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict such changes, our ability to mitigate the risk may be limited depending upon market conditions. Furthermore, the bankruptcy of one or more of our hedge counterparties, or some other similar proceeding or liquidity constraint, would make it unlikely we would be able to collect all or a significant portion of amounts owed to us by the distressed entity or entities. During periods of falling commodity prices, our derivative receivable positions increase, which increases our exposure to the counterparties. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss. ### Risks related to our operations ***Drilling is an uncertain and costly activity***. The cost of drilling, completing, and operating a well is often uncertain, and many factors can adversely affect the economics of a well. Our efforts will be uneconomical if we drill dry holes or wells that are productive but do not produce enough natural gas, NGLs and oil to be commercially viable after drilling, operating and other costs. There is no way to conclusively know in advance of drilling and testing whether any particular prospect will yield natural gas, NGLs or oil in commercially viable quantities. Furthermore, our drilling and producing operations may be curtailed, delayed, or canceled as a result of a variety of factors, including, but not limited to: - increases in the costs, shortages or delivery delays of drilling rigs, equipment, water for hydraulic fracturing services, labor, or other services; - unexpected operational events and drilling conditions; - reductions in natural gas, NGLs or oil prices; - limitations in the market for natural gas, NGLs or oil; - facility or equipment malfunctions or operator error; - equipment failures or accidents; - loss of title and other title-related issues; - pipe or cement failures and casing collapses; - compliance with, or changes in, permitting, environmental, tax and other governmental requirements; - environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures, and unauthorized discharges of hazardous materials; - lost or damaged oilfield drilling and service tools; - unusual or unexpected geological formations; - loss of drilling fluid circulation; - pressure or irregularities in geological formations; - fires, surface craterings, blowouts or explosions; - uncontrollable flows of oil, natural gas or well fluids; - availability and timely issuance of required governmental permits and licenses; and - civil unrest or protest activities. If any of these factors were to occur, we could lose all or a part of our investment or we could fail to realize the expected benefits, either of which could materially and adversely affect our revenue and profitability. Our operations involve utilizing drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling horizontal wells include, but are not limited to, the following: - landing the wellbore in the desired drilling zone; - drilling the wellbore to the full planned length; - staying in the desired drilling zone while drilling horizontally through the formation; - running casing the entire length of the wellbore; and - being able to run tools and other equipment consistently through the horizontal wellbore. Risks that we face while completing horizontal wells include, but are not limited to, the following: - the ability to fracture stimulate the planned number of stages; - the ability to run tools the entire length of the wellbore during completion operations; and - the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage. ***Our identified drilling locations are scheduled out over multiple years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling***. Unless we successfully replace the reserves that we produce, our reserves will decline as reserves are depleted, eventually resulting in a decrease in production and lower revenues and cash flow from operations. Our management team has specifically identified and scheduled certain drilling locations for future multi-year drilling activities on our existing acreage. Our ability to drill and develop these locations depends on a number of uncertainties, including natural gas and oil prices, the availability and cost of capital, drilling and production costs, the availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, permits, regulatory and zoning approvals and other factors. Because of these uncertain factors, we do not know if all of the numerous drilling locations we have identified will ever be drilled. In addition, unless production is established within the spacing units covering the undeveloped acres for which some of the drilling locations are obtained, the leases for such acreage will expire. These risks are greater at times and in areas where the pace of our exploration and development activity slows. As such, our actual drilling activities may materially differ from those presently identified. In addition, we will require significant capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any drilling activities we are able to conduct on these locations may not be successful or result in our ability to add proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our business and results of operations and financial condition. ***Our business is subject to operating hazards that could result in substantial losses or liabilities that may not be fully covered under our insurance policies***. While we have processes and procedures that we utilize to mitigate operational risks, natural gas, NGLs and oil operations are subject to many risks, including well blowouts, craterings, explosions, uncontrollable flows of oil, natural gas or well fluids (especially those that reach surface water or groundwater), fires, pipe or cement failures, pipeline ruptures or spills, vandalism, pollution, releases of toxic gases, geological formations with abnormal or unexpected pressures, adverse weather conditions or natural disasters and other environmental hazards and risks. In addition, our operations are sometimes near populated commercial or residential areas. If any of these hazards occur, we could sustain substantial losses as a result of: - personal injury or loss of life; - damage to or destruction of property, natural resources and equipment; - pollution or other environmental damage; - investigatory and cleanup responsibilities; - regulatory investigations and penalties or lawsuits; - suspension of operations by regulatory authorities; and - repairs and remediation to resume operations. We maintain insurance against many, but not all, potential losses or liabilities arising from our operations in accordance with what we believe are customary industry practices and in amounts and at costs that we believe to be prudent and commercially practicable. Our insurance includes deductibles that must be met prior to recovery, as well as sub-limits and/or self-insurance. Additionally, our insurance is subject to exclusions and limitations. Our insurance does not cover every potential risk associated with our operations, including the potential loss of significant revenues. We can provide no assurance that our insurance coverage will adequately protect us against liability from all potential consequences, damages and losses. We may elect not to purchase insurance in instances where we determine that the cost of available insurance is excessive relative to the risks we believe are presented. However, such determinations may prove to be incorrect. Further, some forms of insurance may become unavailable in the future. If we incur liability from a significant event and the damages are not covered by insurance or are in excess of policy limits, then we would have lower revenues and funds available to us for our operations, that could, in turn, have a material adverse effect on our business, financial condition and results of operations. Additionally, we rely to a large extent on facilities owned and operated by third parties, in particular gas transportation and processing facilities, and damage to, or destruction of, those third-party facilities could affect our ability to process, transport and sell our production. To a limited extent, we maintain business interruption insurance related to three third-party processing plants and connecting lines for our wells in Pennsylvania where we are insured for potential catastrophic losses from the interruption of production caused by a covered loss of or damage to the processing plants; however, such insurance is limited and may not adequately protect us from all potential consequences, damages and losses. ***Our producing properties are concentrated in the Pennsylvania portion of the Appalachian Basin, making us vulnerable to risks associated with operating in one geographic and political region***. Essentially 100% of our total estimated proved reserves are located in the Appalachian Basin in Pennsylvania. We are additionally vulnerable to processing and transportation constraints for our products. We are more heavily exposed to the extensive and evolving regulatory environment in Pennsylvania which may lead to additional costs, delays or interruptions of construction, development and production from our wells. See also *The natural gas industry is subject to extensive regulation* below. Additionally, local governments in Pennsylvania are authorized to adopt and implement ordinances and impose certain restrictions regarding siting of our well sites, tank pads and other related facilities. Approval from one or more local governmental bodies, some following a public hearing, may be required before commencing construction of our facilities which can result in delay, increased expense or in some cases, prevention of development. Moreover, new initiatives or regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of substances generated by our operations, including, but not limited to, produced water, drilling fluids and other wastes associated with our operations or propose new setback distances. For example, in November 2023, Pennsylvania Governor Josh Shapiro instructed the DEP to take immediate action to pursue formal rulemakings and policy changes, including new requirements for the disclosure of chemicals used in drilling, improved control of methane emissions aligned with federal policy, stronger drilling waste protections (including inspection of secondary containment) and corrosion protections for gathering lines that transport natural gas. Currently there are a few states that have elected to ban hydraulic fracturing altogether, including Washington, New York, Maryland, Vermont and Oregon (which temporarily suspended hydraulic fracturing until 2025). Should Pennsylvania or the federal government ban hydraulic fracturing, it would preclude economic development of our Marcellus Shale reserves resulting in severe financial consequences to us. ***We use a significant amount of water in our hydraulic fracturing operations. Our inability to locate sufficient amounts of water or dispose of or recycle water used in our operations may have a material adverse effect on our financial condition, results of operations and cash flows.*** Water is an essential component of our drilling and hydraulic fracturing processes. Limitation or restrictions on our ability to secure sufficient amounts of water (including limitations from natural causes such as drought) could impact our operations. If we are unable to obtain water to use in our operations from local sources, we may need to obtain it from new sources and transport the water to drilling sites, resulting in increased costs. We must either dispose of or recycle water used in our operations. Compliance with environmental and permit requirements governing the withdrawal, storage and use of recyled water, surface water or groundwater may increase costs and cause delays, interruptions or termination of our operations. ***Our business depends on natural gas and oil transportation and NGLs processing facilities which are owned by others and depends on our ability to contract with those parties***. Our ability to sell our natural gas, NGLs and oil production depends in part on the availability, proximity and capacity of gathering and transportation pipeline systems, processing facilities, rail cars, trucks or vessels owned by third parties and our ability to contract with those third parties. The lack of available capacity on these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. See also above *Our producing properties are concentrated in the Pennsylvania portion of the Appalachian Basin, making us vulnerable to risks associated with operating in one geographic and political region.* Although we have some contractual control over the transportation of our products, material changes in these business relationships, including the financial condition of the contractual counterparties, could materially affect our operations. In some cases, we do not purchase firm transportation on third-party facilities and as a result, our production transportation can be interrupted by those having firm arrangements. In other cases, we have entered into firm transportation arrangements where we are obligated to pay fees on minimum volumes regardless of actual volume throughput. If production decreases due to reduced or delayed developmental activities, the current commodity price environment, production related difficulties or otherwise, we may be unable to utilize all of our rights under existing firm transportation contracts, resulting in obligations to pay fees without receiving revenue from sales. Such fees may be significant and may have a material adverse effect on our operations. We have also entered into long-term agreements with third parties to provide natural gas gathering and processing services. In some cases, the capacity of gathering systems and transportation pipelines may be insufficient to accommodate production from existing and new wells. Federal and state regulation of natural gas and oil production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and transport natural gas, NGLs and oil. If any of these third-party pipelines or other facilities become partially or fully unavailable to transport or process our product, or if the natural gas quality specifications for a natural gas pipeline or facility change so as to restrict our ability to transport natural gas on those pipelines or facilities, our revenues could be adversely affected. The disruption of third-party facilities due to maintenance, mechanical failures, accidents, weather and/or other reasons could negatively impact our ability to market and deliver our products. In particular, the disruption of certain third-party natural gas processing facilities that support our core operating area in southwest Pennsylvania could materially affect our ability to market and deliver natural gas production in that area especially if such disruption were to last for more than a short duration which could result in the necessity to curtail a significant amount of our production. We have no control over when or if such facilities are restored and generally have no control over what prices will be charged. A total shut-in of production could severely affect us due to a lack of cash flow, and if a substantial portion of the production volume is hedged at lower than market prices, our obligation to the counterparty under those financial hedges would have to be paid from borrowings thus further adversely affecting our financial condition. ### Risks related to the industry in which we operate ***The natural gas industry is subject to extensive regulation***. Natural gas, NGLs, condensate and other hydrocarbons, as well as our operations to produce these products, are subject to extensive laws, regulations, and ordinances at the federal, state and local level. Further, new legislation, proposed rulemaking and ordinance amendments affecting the industry are under constant review for more expansive requirements and rules on our products and operations. Compliance with new and expanding laws from numerous governmental departments and agencies often increases our cost of doing business, delays our operations and decreases our profitability. Certain potential legislation, such as a ban on hydraulic fracturing, could even preclude our ability to economically develop our reserves. Matters subject to laws and regulations affecting our business include, but are not limited to: the amount and types of substances and material that may be released into the environment, including GHGs; responding to unexpected releases of regulated substances or materials to the environment; the sourcing and disposal of water used in the drilling and completions process; permits, performance rules and reporting obligations concerning drilling, completion and production operations; threatened or endangered species and waterway protection efforts; and climate related initiatives. *Environmental regulations and pollution liability could expose us to significant costs and penalties*. We may incur significant costs and liabilities in complying with existing or future environmental laws, regulations and enforcement policies or initiatives. Some of these environmental laws and regulations may impose strict, joint and several liability regardless of fault or knowledge, which could subject us to liability for conduct that was lawful at the time it occurred, or conditions caused by prior owners or operators or which relate to third party sites where we have taken materials for recycling or disposal. Pennsylvania law also imposes criminal liability for certain releases of substances, regardless of fault or intent. Failure to comply with these laws and regulations may result in the occurrence of delays, cancellations or restrictions in permitting or performance of our projects or other operations and subject us to administrative, civil and/or criminal penalties, corrective actions and orders enjoining some or all of our operations. Our operations may be impacted by new and amended laws and regulations and reinterpretations of existing laws and regulations or increased government enforcement relating to environmental laws. For example, properly handled drilling fluids and produced water are currently exempt from regulation as hazardous waste under RCRA, and instead are regulated under RCRA’s non-hazardous waste provisions. It is possible that the EPA may in the future propose rulemaking that designates such wastes as hazardous rather than non-hazardous, and a similar designation may be made at the state level. Should this occur at the federal and/or state level it could result in significant costs to attain and maintain compliance. We may also be exposed to liability and costs for handling of hydrocarbons, air emissions and wastewater or other fluid discharges related to our operations and waste disposal practices. Spills or other unauthorized releases of hazardous or regulated substances by us, our contractors or resulting from our operations could expose us to material losses, expenditures and liabilities, civil and criminal liabilities, under environmental laws and regulation and we are currently and have in the past been involved in such investigations, remediation and monitoring activities. The Pennsylvania Office of the Attorney General has publicly announced investigations and charges generally related to our industry in Pennsylvania. Additionally, neighboring landowners and other third parties may assert claims or file lawsuits against us for personal injury and/or property damage allegedly caused by the release of substances into the environment, with or without evidence of an impact from our operations, all of which could also result in significant litigation or settlement costs as well as reputational harm. *Laws and regulations pertaining to threatened and endangered species and protection of waterways could delay or restrict our operations and cause us to incur substantial costs*. Various federal and state statutes prohibit actions or operations that adversely affect endangered or threatened species and their habitats. These statutes include the federal Endangered Species Act of 1973 ("ESA"), the Migratory Bird Treaty Act, the CWA, CERCLA and similar state programs. The United States Fish and Wildlife Service ("FWS") may designate critical habitat and suitable habitat areas that it believes are necessary for survival of threatened or endangered species. A critical habitat or suitable habitat designation could result in material restrictions to land use and delay, restrict or even prevent our operations. The Biden administration has taken action to broaden enforcement under ESA, including expanding the definition of critical habitat. While none of the species listed by FWS as threatened or endangered materially affect our operations at the present time, the future designation of previously unprotected species as threatened or endangered in areas where we conduct our operations or expansion of areas designated as critical habitat could cause us to incur increased costs arising from species protection measures and/or limit or prevent our ability to operate which could have an adverse effect on our ability to develop and produce reserves. Additionally, operations may be impacted by the existence of wetlands or other environmentally sensitive areas based upon the scope of the CWA and its protection of waters of the United States. On December 30, 2022, the EPA announced a final rule related to a revised definition of waters of the United States that included a broader interpretation similar to the pre-2015 definition. However, on May 5, 2023, the Supreme Court issued a landmark ruling in *Sackett* v. EPA significantly narrowing the scope of the EPA's definition of the "waters of the United States". The EPA subsequently published a new final rule on September 8, 2023 defining "waters of the United States" to conform to the Supreme Court's ruling in *Sackett*, thereby narrowing the scope of federal jurisdiction under the CWA. The EPA may change its rules in the future. To the extent that legal challenges or any further rulemaking expands the CWA’s jurisdiction we could incur increased costs and restrictions, and/or delays or cancellations in permitting or projects, which could result in significant costs and liabilities or financial losses. *Climate related regulations and initiatives could expose us to significant costs and restrictions on operations*. There is an ongoing public debate as to the extent to which our climate is changing, the potential causes of climate change and its potential impacts. As part of that debate, there is also general belief that increased levels of GHGs, including carbon dioxide and methane, have contributed to and continue to contribute to climate change which has led to numerous regulatory, political, litigation and financial risks associated with the production of fossil fuels and emissions of GHGs. Our operations result in GHGs. Federal and state governments have from time to time considered legislation and regulations to reduce GHG emissions, including, but not limited to the implementation of GHG monitoring and reporting for the natural gas industry which includes certain of our operations. The EPA has sought to achieve these reductions under the Clean Air Act and the NSPS aimed at volatile organic compounds ("VOCs") including methane emissions from oil and natural gas sources. On December 2, 2023, the EPA released a copy of its final rule on NSPS to sharply reduce emissions of methane and other air pollution from oil and natural gas operations. The final rule will, among other things (i) require states to reduce methane emissions from hundreds of thousands of existing sources nationwide for the first time, (ii) phase out routine flaring from new natural gas wells (iii) require the deployment of innovative and advanced monitoring technologies by establishing performance requirements that can be met by a broader array of technologies, (iv) leverage data collected by certified third parties to identify and address "super emitting" sources and eliminate or minimize emissions from common pieces of equipment used in oil and gas operations such as process controllers, pumps and storage tanks and (v) require documentation that wells are properly closed and plugged before monitoring is allowed to end. In response to feedback received during the comment period, the EPA adjusted several provisions of this proposed rule to allow extended time for compliance, including a two-year phase-in period for eliminating routine flaring of natural gas that is emitted from new oil wells. Additional costs are likely to result from compliance with the final rule based on expanded monitoring requirements and more stringent emissions limits. Additionally, the EPA proposed rules pursuant to the 2022 Inflation Reduction Act that would charge a fee associated with certain levels of methane emissions. In Pennsylvania, regulators have implemented operating permits and restrictions on emissions for well site operations, compressors, processing plants and other downstream facilities that directly impact our operations. The DEP is implementing new and additional regulations to limit VOCs from existing sources for the oil and gas industry. There have also been a number of state and regional efforts that have emerged that seek to track and reduce GHG emissions by means of cap and trade programs where emitters would be required to acquire and surrender emission allowances in return for emitting GHGs. In September 2020, the PEQB approved a draft resolution to enter the Regional Greenhouse Gas Initiative ("RGGI"), a cooperative effort among the states of Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island and Vermont to cap and reduce power sector CO2 emissions from fossil-fuel-fired electric power plants. However, in response to the PEQB's resolution to join the RGGI, the Pennsylvania General Assembly adopted a resolution on December 15, 2021, expressing its disapproval of the state's efforts to enroll in RGGI, stating that the RGGI would drive up energy costs and result in thousands of lost jobs. On January 10, 2022, former Governor Wolf vetoed the disapproval resolution. In April 2022, the Pennsylvania senate failed to override former Governor Wolf's veto and as a result, Pennsylvania officially joined the RGGI. However, in July 2022, the Commonwealth Court of Pennsylvania issued an order blocking the state from participating in the RGGI until the court ruled on its constitutionality. On November 1, 2023, the Pennsylvania Commonwealth Court ruled that funds generated through the RGGI are an unconstitutional tax, effectively preventing the state from participating in RGGI. Pennsylvania Governor Josh Shapiro appealed that decision to the state's Supreme Court. Moreover, in 2023, Pennsylvania Governor Josh Shapiro created the "RGGI Working Group" and tasked them with measuring RGGI or an alternative against a three-part test: protect and create energy jobs, take real action to address climate change, and ensure reliable, affordable power for consumers in the long-term. While the RGGI Working Group agreed that a cap-and-trade regulation would meet these goals, they did not conclude that RGGI is the correct program for Pennsylvania, citing wider concerns regarding increased energy costs and job loss. The RGGI Working Group gave Governor Shapiro a list of recommendations in a four-page memo, suggesting, among other things, Governor Shapiro explore a cap-and-trade program that includes Washington, D.C. and 13 states whose electric grids are run by PJM Interconnection, while encouraging the PJM-run states to reach consensus on carbon trading. To date, Governor Shapiro has not taken any official action in response to the RGGI Working Group's recommendations. In the absence of participation in the RGGI, the DEP is evaluating other regulations to achieve the emissions reductions. We have initiated our own internal goals to reduce GHG emissions from our operations. For example, setting a goal of net zero Scope 1 and 2 GHG emissions by 2025; however, there are a variety of factors that may prevent us from meeting that goal including but not limited to operational malfunctions, availability of equipment and services, engineering results, capital constraints and availability and success of carbon offsetting initiatives. Given uncertainties related to the use of emerging technologies, the state of markets for, and the validity and availability of verified carbon offsets along with the uncertainty of emission measurement calculations, we cannot predict whether or not we will be able to timely meet our net zero GHG emissions goal. We continue to evaluate a range of technology and other measures, such as carbon offsets, that could assist with meeting this goal. Failure or a perception (whether or not valid) of failure to meet our GHG emissions goals, could damage our reputation and negatively impact our stock price. The outcome of federal, state and regional actions to address global climate change could result in a variety of new laws and regulations to control or restrict emissions including taxes or other charges to deter or restrict emissions of GHGs. This may also depend upon political outcomes as there have been certain candidates seeking election to various state and federal offices or their appointees, who have made pledges to restrict GHG emissions, ban hydraulic fracturing of oil and natural gas wells and ban new leases for production of oil and natural gas on federal lands. Our reserves development is critically dependent upon the use of hydraulic fracturing and we cannot economically develop any of our reserves without using such technology (which we believe has been safely conducted for many decades) and a ban of such technology could result in severe economic harm to us. There are also increasing litigation risks associated with climate change concerns as a number of cities and local governments have initiated lawsuits against fossil fuel producers in state and federal court asserting claims for public nuisance and seeking damages for climate change impacts to roadways and infrastructure. Such lawsuits have also alleged that fossil fuel producers have been aware of the adverse effects of climate change and defrauded their investors by failing to adequately disclose those impacts. Financial risks for fossil fuel energy companies, including natural gas producers, are also on the rise as stockholders and bondholders concerned about the potential effects of fossil fuels on climate change may elect to shift some or all of their investments away from fossil fuel based energy. Institutional lenders who provide financing to fossil fuel energy companies also have been under pressure from activists and are the subject of lobbying to not provide funding for fossil fuel production. Also, in November 2021, the Federal Reserve issued a statement in support of the efforts of the Network of Greening the Financial System, of which the Federal Reserve is a member, to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. Some of these institutional lenders may elect not to provide funding for us which could result in restriction, delay or cancellation of drilling programs or development or production activities or impair our ability to operate economically. On March 21, 2022, the SEC issued a proposed rule regarding the enhancement and standardization of mandatory climate-related disclosures. The proposed rule would require registrants to include certain climate-related disclosures in their registration statements and periodic reports. The SEC is expected to release the final rule in April of 2024. While the final form and substance of these requirements are not yet known and the ultimate scope and impact on our business is uncertain, compliance with the proposed rule may result in increased legal, accounting, operational, technology and financial compliance costs. Certain organizations that provide corporate governance and other corporate risk information to investors and stockholders have developed scores and ratings to evaluate companies and investment funds based on sustainability or environmental, social and governance ("ESG") metrics. Currently, there are no universal standards for such scores or ratings, but the importance of sustainability evaluations is becoming more broadly accepted by investors and stockholders. A number of advocacy groups, both domestically and internationally, have campaigned for governmental and private action to promote change at public companies related to ESG matters, including through investment and voting practices of investment advisors, public pension funds, universities and other members of the investing community. As a result, many investment funds focus on positive ESG business practices and sustainability scores when making investments. Companies which do not adapt to or comply with investor or stockholder ESG expectations and standards or which are perceived to have not responded appropriately to the growing concern for ESG issues, regardless of whether there is a legal requirement to do so, may suffer from reputational damage and the financial condition, results of operations or cash flows of such a company could be materially and adversely affected. Moreover, we may from time-to-time create and publish voluntary disclosures regarding ESG matters. Many of the statements in those voluntary disclosures are 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. At this time, we cannot predict the potential impact of such laws, regulations, regional or international initiatives or compacts, litigation, ESG ratings or financing restrictions due to climate concerns on our future consolidated financial condition, results of operations or cash flows; however, such impacts could be material and have material negative consequences to our business. ***Information concerning our reserves and future net cash flow are estimates and are not certain to match our results***. There are numerous uncertainties inherent in estimating quantities of proved natural gas and oil reserves and their values, including many factors beyond our control. Estimates of proved reserves depend on many assumptions relating to current and future economic conditions and commodity prices as well as the projected productivity of our wells and infrastructure to gather, process, store and/or transport our products to market. To the extent we experience a sustained period of reduced commodity prices, there is a risk that a portion of our proved reserves could be deemed uneconomic and no longer be classified as proved. Although we utilize robust processes and procedures to evaluate and estimate our reserves, they are estimates and the actual production, revenues and costs to develop our estimated reserves will vary from estimates and these variances could be material and/or negative. Reserve estimation is a subjective process that involves estimating volumes to be recovered from underground accumulations of natural gas and oil that cannot be directly measured. As a result, different petroleum engineers, each using industry-accepted geologic and engineering practices and scientific methods, may calculate different estimates of reserves and future net cash flows based on the same available data. Because of the subjective application of engineering principles to natural gas, NGLs and oil reserve estimates, each of the following items may differ materially from the amounts or other factors estimated: - the amount and timing of natural gas, NGLs and oil production; - the revenues and costs associated with that production; - the amount and timing of future development expenditures; and - future commodity prices. The discounted future net cash flows from our proved reserves included in this report are not the same as the market value of the reserves attributable to our properties. As required by United States generally accepted accounting principles ("U.S. GAAP"), the estimated discounted future net revenues from our proved reserves are based on a twelve month average price (first day of the month) while cost estimates are based on current year-end economic conditions. Actual future prices and costs may be materially higher or lower. In addition, the ten percent discount factor that is required to be used to calculate discounted future net cash flows for reporting purposes under U.S. GAAP is not necessarily the most appropriate discount factor based on the cost of capital, which varies from time to time, and risks associated with our business and the oil and gas industry in general. ***We may face various risks associated with the long-term trend toward increased activism against oil and gas exploration and development activities***. Opposition toward oil and gas drilling and development activity has been growing over time. Companies in the oil and gas industry are often the target of activist efforts to delay or prevent oil and gas development from both individuals and non-governmental organizations who use safety, environmental compliance and business practices to support their opposition to oil and gas drilling. Anti-development activists are working to, among other things, reduce access to federal and state government lands, delay or cancel certain projects such as the development of oil and gas drilling or export facilities, as well as the pipeline infrastructure needed to transport and process oil and gas production. For example, environmental activists continue to advocate for increased regulations or bans on shale drilling and hydraulic fracturing in the United States, even in jurisdictions like Pennsylvania that are among the most stringent in their regulation of the industry. Such activist efforts could result in the following: - delay or denial of drilling permits; - restrictions on or prevention of installation or operation of production, gathering or processing facilities; - restrictions on or prevention of the use of certain operating practices, such as hydraulic fracturing, or the disposal of related materials, such as hydraulic fracturing fluids and produced water; - additional regulatory burdens; - increased severance and/or other taxes; - cyber-attacks; - legal challenges or lawsuits; - negative publicity about our business or the oil and gas industry in general; - increased costs of doing business; - reduction in demand for our products; and - other adverse effects on our ability to develop our properties and expand production. We may incur significant costs associated with responding to these initiatives and such actions may materially adversely affect our financial results. Complying with any resulting additional legal or regulatory requirements that are substantial or prevent our activity could have a material adverse effect on our business, financial condition, cash flows and results of operations. ***Conservation measures and technological advances could reduce demand for oil and natural gas***. Fuel conservation measures, alternative fuel requirements, governmental requirements for renewable energy resources, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation or storage devices (such as battery technology) may in the future, reduce the demand for and, in turn the prices of, natural gas, NGLs and oil that we sell. In addition, these measures may reduce the availability to us of necessary third-party services and facilities that we rely on which could increase our operational costs and adversely impact our ability to produce, transport and process natural gas, NGLs and oil. The impact of changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows. ### Legal, tax and regulatory risks ***U.S. or state tax legislation may adversely affect our business, results of operations, financial condition and cash flow .*** Legislation is periodically proposed that could make significant changes to United States federal income tax laws and could include the elimination of certain United States federal income tax benefits currently available to oil and gas exploration and production companies including, but not limited to, (i) the repeal of percentage depletion allowances for oil and natural gas properties; (ii) the elimination of current deductions for intangible drilling and development costs and; (iii) an extension of the amortization period for certain geological and geophysical expenditures. Additionally, legislation could be enacted that imposes new fees or increases the taxes on oil and natural gas extraction, which could result in increased operating costs and/or reduced consumer demand for our products. The passage of any such legislation or any other similar change in United States federal income tax law could increase costs or eliminate or postpone certain tax deductions that are currently available with respect to natural gas and oil exploration and development and any such changes could have an adverse effect on our financial condition, results of operations and cash flows. In 2022, legislation commonly known as the Inflation Reduction Act was signed into law, which includes, among other things, a corporate alternative minimum tax (the "CAMT") and a one percent excise tax on corporate stock repurchases. The CAMT generally treats a corporation as an applicable corporation in any taxable year in which the average annual adjusted financial statement income for a three taxable-year period ending prior to such taxable year exceeds $1.0 billion. If we become subject to CAMT, our cash obligations for U.S. federal income taxes could be significantly accelerated. To the extent the 1% excise tax applies to repurchases of shares under our common stock repurchases program, the number of shares we repurchase and our cash flow may be affected. In 2012, Pennsylvania enacted legislation creating a tax referred to as the natural gas impact fee applicable to production in Pennsylvania, where all of our acreage is located. The legislation imposes an annual fee on natural gas and oil operators for each well drilled for a period of fifteen years. Much like a severance tax, the fee is on a sliding scale set by the Pennsylvania Public Utility Commission and is based on two factors: changes in the Consumer Price Index and the average NYMEX natural gas prices on the last day of each month. The impact fee increases the financial burden on our operations in the Marcellus Shale. There can be no assurance that the impact fee will remain as currently structured or that additional taxes will not be imposed. From time to time, the Pennsylvania Governor and various Pennsylvania state lawmakers have proposed legislation to enact a severance tax in substitution for, or as an addition to, the impact fee already in place. The structure of and ultimate effect of any additional tax burden cannot be estimated at this time but could be material. ***Legal proceedings brought against us could result in substantial liabilities and materially and adversely impact our financial condition***. Like many oil and gas companies, we are involved in various legal proceedings, including threatened claims, such as title, royalty, and contractual disputes. The cost to settle legal proceedings (asserted or unasserted) or satisfy any resulting judgment against us in such proceedings could result in a substantial liability or the loss of interests, which could materially and adversely impact our cash flows, operating results and financial condition. Judgments and estimates to determine accruals or range of losses related to legal proceedings could change from one period to the next, and such changes could be material. Current accruals may be insufficient to satisfy any such judgments. Legal proceedings could also result in negative publicity about Range. In addition, legal proceedings distract management and other personnel from their primary responsibilities. At this time, based on the information available to management, there are no pending claims or litigation which appear likely to result in a material financial impact. However, management’s assessment of pending claims and litigation could be inaccurate and subsequent events could result in material liabilities from such claims or litigation. ***Our success depends on key members of our management and our ability to attract and retain experienced technical and other professional personnel***. None of our senior management team nor any of the other officers are subject to an employment agreement and therefore retaining them as employees is less certain than if they were parties to an employment agreement. The unanticipated loss of one or more of these individuals could have a material adverse effect on our business. Further, the loss of key technical professionals with extensive experience in our core operating area could be difficult to replace if they were to leave and the loss of such employees could adversely affect the costs of drilling, completing and operating our wells. ### Risks related to our common stock ***Common stockholders may be diluted if additional shares are issued***. In order to align interests and encourage ownership, we issue restricted stock 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 senior notes or other securities or debt convertible into common stock to extend maturities or fund capital expenditures, including acquisitions. The issuance of additional shares of common stock results in dilution of the interests of existing stockholders. One way to reverse the effects of dilution is by the acquisition of our stock. On December 31, 2023, our share repurchase program has $1.1 billion remaining. However, this program may be suspended, modified or discontinued by the board of directors at any time. ***Dividend limitations***. Limits on the payment of dividends and other restricted payments (as defined in our bank credit facility) are imposed under our bank credit facility. These limitations may, in certain circumstances, limit or prevent the payment of dividends. ***Our stock price may be volatile and stockholders may not be able to resell shares of our common stock at or above the price they paid***. The price of our common stock fluctuates significantly, which may result in losses for investors. The market price of our common stock has been volatile. From January 1, 2021 to December 31, 2023, the price of our common stock reported by the New York Stock Exchange ranged from a low of $6.78 per share to a high of $37.88 per share. We expect our stock price to continue to be subject to volatility as a result of a variety of factors, including factors beyond our control. These factors include: - most significantly, changes in natural gas, NGLs and oil prices; - variations in drilling, recompletions, acquisitions and operating results; - changes in governmental regulation and/or taxation; - changes in financial estimates by securities analysts; - changes in market valuations of comparable companies; - expectations regarding our capital program, including any determination by our board of directors regarding repurchasing stock or paying dividends; - changes in key personnel; or - future sales of additional stock and changes in our capital structure. We may fail to meet expectations of our stockholders or of securities analysts at some time in the future and our stock price could decline as a result. ### General risk factors ***Our business could be negatively affected by security threats, including cybersecurity threats and other disruptions***. The United States government has issued public warnings that indicate that energy assets might be specific targets of cybersecurity threats. As a natural gas and oil producer, we face various security threats, including: - cybersecurity threats to gain unauthorized access to sensitive information or to render data or computer systems unusable; - threats to the security or operations at our physical facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines; or - threats from terrorist acts or other geopolitical events. Digital technologies are an integral part of our business and are used to support our exploration, development and production activities and our key accounting and financial reporting functions. We use these systems to analyze and store financial and operating data and to communicate internally and with outside business counterparties. Cyberattacks could compromise our core infrastructure and digital technologies and result in disruptions to our business operations or the loss of our data and proprietary information. In addition, digital technologies control oil and gas production, processing equipment, and distribution systems globally and are necessary to deliver our production to market. A cyberattack against these operating systems, or the networks and infrastructure on which they rely, could damage critical production, distribution and/or storage assets, delay or prevent delivery to markets, cause accidental discharge and/or make it difficult or impossible to accurately account for production and settle transactions. A cyberattack on a vendor or a service provider could result in supply chain disruptions, which could delay or halt development projects. A cyberattack on our accounting or human resources systems could expose us to liability if personal information is obtained. Furthermore, the shift to a hybrid systems model including on-premises and cloud environments has transformed how systems interconnect, how data is stored, how users interact with applications and what end user devices are utilized. This shift has resulted in additional cybersecurity risk. Security threats have subjected our operations to increased risks that could have a material adverse effect on our business. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our personnel, information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to harm to our employees or losses of sensitive information, losses of critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, and results of operations or cash flows. Attackers are becoming more sophisticated and both the frequency and magnitude of cyberattacks in particular are expected to increase and include, but are not limited to, malicious software, phishing, ransomware, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. These events could damage our reputation and lead to financial losses from unauthorized disbursement of funds, remedial actions, loss of business and/or potential liability. We may be unable to anticipate, detect or prevent future attacks, particularly as methodologies utilized by attackers change frequently and are not recognized until launched. Additionally, the continuing and evolving threat of cybersecurity attacks has resulted in evolving legal and compliance matters, including increased regulatory focus on prevention, which could require us to expend significant additional resources to meet such requirements. While we utilize extensive processes and procedures that we deem appropriate to counter cybersecurity risks and to date have not suffered any material losses relating to such attacks, there can be no assurance that we will not suffer such losses in the future. Any losses, costs or liabilities directly or indirectly related to cyberattacks or similar incidents may not be covered by, or may exceed the coverage limits of, any of our insurance policies. 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 areas around the world 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. ## Cybersecurity As filed, 2,642 characters. We have a comprehensive approach to mitigate cybersecurity risk which primarily focuses on three key elements: - People - security awareness education and readiness-testing throughout the year for employees and contractors; - Process - incorporating "cyber awareness" in our day-to-day processes which includes constant review of alerting and detection to mitigate constant cybersecurity threats, regular review of security posture and security roadmap to ensure alignment throughout the organization, physical and digital asset protection and security vulnerability remediation via preventable and detective measures; and - Technology - investing in industry aligned security technology and threat intelligence capabilities. Cybersecurity governance is supported by our information technology department which includes certified security professionals and seasoned security analysts. This department conducts an extensive periodic review of our security initiatives to assess the current state of our program (using a cybersecurity framework) and potential evolution based on current business risks along with detection and communication of cybersecurity threats and actions to mitigate those threats. Cybersecurity incidents meeting a pre-determined minimum threshold are communicated to a separate committee comprised of officers charged with reporting responsibilities to determine overall materiality and disclosure obligations. We have engaged an independent third-party operations center that is focused on, among other things, monitoring alerts, logs, behavior analytics and end devices usage. This continuous monitoring is in conjunction with periodic security assessments, constant vulnerability scanning and frequent penetration tests. We also complete an initial vendor cybersecurity review process for new cloud-based software which provides a standardized review assessment. We monitor known third-party breaches, known software vulnerabilities that may affect third-party vendors and communicate as necessary with those vendors allowing us to increase security of our technology assets and our data. Our board of directors oversees our cybersecurity risk and receives a quarterly cybersecurity report and an update from management which includes additional discussions of any relevant issues related to the understanding of technology and cybersecurity risk that may be relevant at any given time. This report includes, among other things, information regarding our current security posture and on-going cybersecurity events. Cybersecurity incidents meeting a pre-determined minimum threshold are communicated to our Board. ## Legal proceedings As filed, 1,329 characters. We are the subject of, or party to, a number of pending or threatened legal actions, administrative proceedings or investigations arising in the ordinary course of our business including, but not limited to royalty claims, contract claims and environmental claims. While many of these matters involve inherent uncertainty, we believe that the amount of the liability, if any, ultimately incurred with respect to these actions, proceedings or investigations will not have a material adverse effect on our consolidated financial position as a whole or on our liquidity, capital resources or future annual results of operations. We will continue to evaluate our litigation quarterly and will establish and adjust any litigation reserves as appropriate to reflect our assessment of the then-current status of litigation. ### Environmental Proceedings From time to time, we receive notices of violation from governmental and regulatory authorities in areas in which we operate relating to alleged violations of environmental statutes or the rules and regulations promulgated thereunder. While we cannot predict with certainty whether these notices of violation will result in fines and/or penalties, if fines and/or penalties are imposed, they may result in monetary sanctions, individually or in the aggregate, in excess of $250,000. ## Management's discussion and analysis As filed, 77,410 characters. ### OPERATIONS The following discussion is intended to assist you in understanding our business and results of operations together with our present financial condition and should be read in conjunction with the information under Item 8. Financial Statements and Supplementary Data and other financial information found elsewhere in this Form 10-K. See also matters referenced in the foregoing pages under "Disclosures Regarding Forward-Looking Statements." The following tables and discussions set forth key operating and financial data for the years ended December 31, 2023 and 2022. For similar discussions of the year ended December 31, 2022 compared to December 31, 2021 results, refer to Item 7. "Managements’ Discussion and Analysis of Financial Condition and Results of Operations" under Part II of our annual report on Form 10-K for the year ended December 31, 2022, which was filed with the SEC on February 27, 2023. ### Overview of Our Business We are an independent natural gas, natural gas liquids ("NGLs,") crude oil and condensate company engaged in the exploration, development and acquisition of natural gas and crude oil properties located in the Appalachian region of the United States. We operate in one segment and have a single company-wide management team that administers all properties as a whole rather than by discrete operating segments. We measure financial performance as a single enterprise and not on an area-by-area basis. Our overarching business objective is to build stockholder value through returns-focused development of natural gas properties. Our strategy to achieve our business objective is to generate consistent cash flows from reserves and production through internally generated drilling projects occasionally coupled with complementary acquisitions and divestitures of non-core or, at times, core assets. Currently, our investment portfolio is focused on high quality natural gas assets in the state of Pennsylvania. Our revenues, profitability and future growth depend substantially on prevailing prices for natural gas, NGLs, crude oil and condensate and on our ability to economically find, develop, acquire and produce natural gas, NGLs and oil reserves. Commodity prices have been and are expected to remain volatile. We believe we are well-positioned to manage any challenges during a low commodity price environment and that we can endure the continued volatility in current and future commodity prices by: - exercising discipline in our capital investments; - optimizing drilling, completion and operational efficiencies; - maintaining a competitive cost structure; - managing price risk through the hedging of our production; and - managing our balance sheet. Prices for natural gas, NGLs, crude oil and condensate fluctuate widely and affect: - our revenues, profitability and cash flow; - the quantity of natural gas, NGLs and oil that we can economically produce; - the quantity of natural gas, NGLs and oil shown as proved reserves; - the amount of cash flow available to us for reinvestment; and - our ability to borrow and raise additional capital. We prepare our financial statements in conformity with U.S. GAAP, which require us to make estimates and assumptions that affect our reported results of operations and the amount of our reported assets, liabilities and proved natural gas, NGLs and oil reserves. We use the successful efforts method of accounting for our natural gas, NGLs and oil activities. Our corporate headquarters is located in Fort Worth, Texas. ### Key 2023 highlights include: ### Financial and operating results: - We recorded net income of $871.1 million for the year ended December 31, 2023; - Average daily production was 2.14 Bcfe during the year; - Repurchased 715,000 shares of common stock via the share repurchase program leaving $1.1 billion available under the repurchase program; - Paid dividends of $77.2 million, ending the year with $212.0 million in cash on hand; and - Executed opportunistic debt repurchases of $61.6 million in the open market. ### Corporate sustainability highlights and initiatives: - Completed the MiQ certification for our Southwest Pennsylvania assets and earned an "A" grade; - Continued to recycle approximately 100% of our produced water; - Implemented the use of compressed air pneumatic controllers; - Achieved a 28% reduction in number of workforce recordable injuries (both employee and contractor) with a Total Recordable Incident Rate of 0.34; - Achieved a 70% reduction in preventable vehicle incidents with six incidents in 2023; and - Continued board of directors refreshment through the appointment of one new director. ### Management’s Discussion and Analysis of Results of Operations Commodity prices have remained volatile. Benchmarks for natural gas, oil and NGLs decreased in 2023 compared to 2022 and, as a result, we experienced significant decreases in our price realizations when compared to the same period of 2022. Despite lower prices, we continued to focus on creating long-term value for our stockholders along with positioning ourselves to be a responsible and reliable supplier of natural gas. ### Overview of 2023 Results During 2023, we recognized net income of $871.1 million, or $3.57 per diluted common share compared to $1.2 billion, or $4.69 per diluted common share during 2022. The decrease in net income for the year ended December 31, 2023 when compared to 2022 is primarily due to significantly lower realized prices. For the year ended December 31, 2023, we experienced a decrease in revenue from the sale of natural gas, NGLs and oil due to a 41% decrease in net realized prices (average prices including all derivative settlements and third-party transportation costs paid by us) when compared to 2022. Daily production in 2023 averaged 2.14 Bcfe compared to 2.12 Bcfe in 2022. During 2023, our financial and operating performance included the following results: - revenue from the sale of natural gas, NGLs and oil decreased 52% from the same period of 2022 with a 53% decrease in average realized prices (before cash settlements on our derivatives) partially offset by slightly higher production volumes; - revenue from the sale of natural gas, NGLs and oil (including cash settlements on our derivatives) decreased 30% from the same period of 2022; - transportation, gathering, processing and compression expense per mcfe was $1.43 in 2023 compared to $1.61 in the same period of 2022 primarily due to the impact of lower commodity prices; - direct operating expense per mcfe was $0.12 in 2023 compared to $0.11 in the same period of 2022 due to higher workover costs; - general and administrative expense per mcfe for 2023 decreased 5% from the same period of 2022 due to lower stock-based compensation; - interest expense per mcfe for 2023 decreased 24% from the same period of 2022 due to lower debt balances; - our DD&A rate per mcfe for 2023 decreased 2% from the same period of 2022; - drilled 47.4 net wells with a 100% success rate; - cash flow from operating activities for 2023 was 48% lower than the same period of 2022 due to lower commodity prices; and - our capital budget spending for 2023 was $613.6 million, which was within our initially announced range of $570.0 million to $615.0 million. The year ended December 31, 2023 also included the following highlights to enhance our balance sheet, return capital to investors and preserve liquidity: - paid $77.2 million in dividends or $0.32 per share compared to $0.16 in 2022; - repurchased $19.0 million of our common stock compared to $399.7 million in 2022; - repurchased in the open market $61.6 million face value of our 4.875% senior notes due 2025 at a discount; and - enhanced liquidity with the accumulation of cash on hand of $212.0 million along with $1.3 billion available under our credit facility. We generated $977.9 million of cash from operating activities in 2023, a decrease of $886.9 million from 2022 which reflects significantly lower realized prices partially offset by lower comparative working capital outflows. ### Acquisitions During 2023, we invested $40.1 million to acquire unproved acreage compared to $28.7 million in 2022. We continue selective acreage leasing and lease renewals to consolidate our acreage positions in the Marcellus Shale play in Pennsylvania. ### 2024 Outlook As we enter 2024, we believe we are positioned for sustainable long-term success. For 2024, we expect our capital budget to be in the range of $620 million to $670 million for natural gas, NGLs, crude oil and condensate related activities, excluding proved property acquisitions, for which we do not budget. As has been our historical practice, we will periodically review our capital expenditures throughout the year and may adjust the budget based on commodity prices, drilling success and other factors. We expect our 2024 capital budget to achieve production similar to our 2023 production. Our 2024 capital budget is focused on continuing to improve corporate returns and generating free cash flow. We expect it to be funded with operating cash flow. The prices we receive for our natural gas, NGLs and oil production are largely based on current market prices, which are beyond our control. The price risk on a portion of our forecasted natural gas, NGLs and oil production for 2024 is partially mitigated by entering into commodity derivative contracts and we intend to continue to enter into these types of contracts. We believe it is likely that commodity prices will continue to be volatile during 2024. ### Market Conditions We believe we are positioned for sustainable long-term success. We continue to monitor the impact of the actions of OPEC and other large producing nations, the Russia-Ukraine conflict, hostilities in the Middle East, global inventories of oil and gas, future monetary policy and governmental policies aimed at transitioning towards lower carbon energy and we expect prices for some or all of the commodities we produce to remain volatile given the complex dynamics of supply and demand that exist in the global market. In fourth quarter 2023, natural gas prices declined based on the relatively mild early days of winter and delays to a large liquefied natural gas export project in-service date. Longer term natural gas futures prices have remained stronger based on market expectations that associated gas-related activity in oil basins and dry gas basin activity will show modest rates of growth compared with the past due to infrastructure constraints, capital discipline and core inventory exhaustion. In addition, the global energy crisis further highlighted the low cost and low emissions shale gas resource base in North America, supporting continued strong structural demand growth for United States liquefied natural gas exports, domestic industrial gas demand and power generation. Other factors such as geopolitical disruptions, supply chain disruptions, cost inflation, concerns over a potential economic recession and the pace and extent of tightening global monetary policy may impact the demand for oil, natural gas and NGLs. We continue to assess and monitor the impact and consequences of these factors on our operations. Prices for various quantities of natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. Prices for commodities, such as hydrocarbons, are inherently volatile. Recently, natural gas prices have decreased, when compared to December 2023, with the average NYMEX monthly settlement price for natural gas decreasing to $2.49 per mcf for February 2024 with the recent mild winter weather. Crude oil prices have increased, when compared to December 2023, to $73.86 per barrel in January 2024. The following table lists related benchmarks for natural gas, oil and NGLs composite prices for the years ended December 31, 2023 and 2022. | Benchmarks: Average NYMEX prices (a) | Year Ended December 31, 2023 | 2022 | | --- | ---: | ---: | | Natural gas (per mcf) | $2.75 | $6.64 | | Oil (per bbl) | $77.54 | $94.90 | | Mont Belvieu NGLs composite (per gallon) (b) | $0.56 | $0.90 | (a) Based on average of monthly last day settlement prices on the New York Mercantile Exchange ("NYMEX"). (b) Based on our estimated NGLs product composition per barrel. Our price realizations (not including the impact of our derivatives) may differ from the benchmarks for many reasons, including quality, location, or production being sold at different indices. ### Natural Gas, NGLs and Oil Sales, Production and Realized Price Calculations Our revenues vary from year to year as a result of changes in realized commodity prices and production volumes. In 2023, natural gas, NGLs and oil sales decreased 52% from 2022 with a 53% decrease in realized prices (excluding cash settlements on our derivatives) partially offset by slightly higher production volumes. The following table illustrates the primary components of natural gas, NGLs, crude oil and condensate sales for the last two years (in thousands): | Natural gas, NGLs and Oil sales | Year Ended December 31, 2023 | 2022 | Change | % Change | | --- | ---: | ---: | ---: | ---: | | Natural gas | $1,234,308 | $3,364,111 | $(2,129,803) | (63%) | | NGLs | 933,791 | 1,308,574 | (374,783) | (29%) | | Oil and condensate | 166,562 | 238,407 | (71,845) | (30%) | | Total natural gas, NGLs and oil sales | $2,334,661 | $4,911,092 | $(2,576,431) | (52%) | Production is maintained through drilling success as we place new wells on production which is partially offset by the natural decline of our natural gas and oil reserves through production. Our production for the last two years is set forth in the following table: | Production (a) | Year Ended December 31, 2023 | 2022 | Change | % Change | | --- | ---: | ---: | ---: | ---: | | Natural gas (mcf) | 538,084,671 | 539,442,624 | (1,357,953) | —% | | NGLs (bbls) | 37,939,700 | 36,392,033 | 1,547,667 | 4% | | Crude oil and condensate (bbls) | 2,475,306 | 2,715,681 | (240,375) | (9%) | | Total (mcfe) (b) | 780,574,707 | 774,088,908 | 6,485,799 | 1% | | **Average daily production (a)** | | | | | | Natural gas (mcf) | 1,474,205 | 1,477,925 | (3,720) | —% | | NGLs (bbls) | 103,944 | 99,704 | 4,240 | 4% | | Crude oil and condensate (bbls) | 6,782 | 7,440 | (658) | (9%) | | Total (mcfe) (b) | 2,138,561 | 2,120,792 | 17,769 | 1% | (a) Represents volumes sold regardless of when produced. (b) Oil and NGLs volumes are converted to mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship between oil and natural gas prices. 40 Our average realized price (including all derivative settlements and third-party transportation costs paid by Range) received during 2023 was $1.88 per mcfe compared to $3.17 per mcfe in 2022. The majority of our production is sold at market-sensitive prices. Generally, if the related commodity index declines, the price we receive for our production will also decline. Because we record transportation costs on two separate bases, as required by U.S. GAAP, we believe computed final realized prices should include the impact of transportation, gathering, processing and compression expense. Average sales prices (excluding derivative settlements) do not include any derivative settlements or third-party transportation costs which are reported in transportation, gathering and compression expense on the accompanying consolidated statements of income. Average sales prices (excluding derivative settlements) do include transportation costs where we receive net proceeds from the purchaser. Our average realized price (including all derivative settlements and third-party transportation costs paid by Range) calculation includes all cash settlements for derivatives. Our derivative settlements included in our realized price calculations do not include settlements of contingent consideration related to the sale of our North Louisiana properties. Average realized price calculations for the last two years are shown below: | Average Prices Average sales prices (excluding derivative settlements): | Year Ended December 31, 2023 | 2022 | Change | % Change | | --- | ---: | ---: | ---: | ---: | | Natural gas (per mcf) | $2.29 | $6.24 | $(3.95) | (63%) | | NGLs (per bbl) | 24.61 | 35.96 | (11.35) | (32%) | | Crude oil (per bbl) | 67.29 | 87.79 | (20.50) | (23%) | | Total (per mcfe) (a) | 2.99 | 6.34 | (3.35) | (53%) | | Average realized prices (including all derivative settlements): | | | | | | Natural gas (per mcf) | $2.77 | $4.16 | $(1.39) | (33%) | | NGLs (per bbl) | 24.61 | 35.62 | (11.01) | (31%) | | Crude oil (per bbl) | 62.77 | 57.39 | 5.38 | 9% | | Total (per mcfe) (a) | 3.31 | 4.78 | (1.47) | (31%) | | Average realized prices (including all derivative settlements and third-party transportation costs paid by Range): | | | | | | Natural gas (per mcf) | $1.68 | $2.90 | $(1.22) | (42%) | | NGLs (per bbl) | 10.80 | 20.08 | (9.28) | (46%) | | Crude oil (per bbl) | 62.43 | 57.39 | 5.04 | 9% | | Total (per mcfe) (a) | 1.88 | 3.17 | (1.29) | (41%) | (a) Oil and NGLs volumes are converted at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil to natural gas, which is not indicative of the relationship between oil and natural gas prices. Realized prices include the impact of basis differentials and gains or losses realized from our basis hedging. The prices we receive for our natural gas can be more or less than the NYMEX price because of adjustments for delivery location, relative quality and other factors. The following table provides this impact on a per mcf basis: | | Year Ended December 31, 2023 | 2022 | | --- | ---: | ---: | | Average natural gas differentials below NYMEX | $(0.46) | $(0.40) | | Realized gains on basis hedging | $0.05 | $0.11 | The following tables reflect our production and average realized commodity prices (excluding derivative settlements and third-party transportation costs paid by Range) (in thousands, except prices): | Natural gas | Year Ended December 31, 2022 | Price Variance | Volume Variance | 2023 | | --- | ---: | ---: | ---: | ---: | | Price (per mcf) | $6.24 | $(3.95) | $— | $2.29 | | Production (Mmcf) | 539,443 | — | (1,358) | 538,085 | | **Natural gas sales** | $3,364,111 | $(2,121,335) | $(8,468) | $1,234,308 | 41 | NGLs | Year Ended December 31, 2022 | Price Variance | Volume Variance | 2023 | | --- | ---: | ---: | ---: | ---: | | Price (per bbl) | $35.96 | $(11.35) | $— | $24.61 | | Production (Mbbls) | 36,392 | — | 1,548 | 37,940 | | **NGLs sales** | $1,308,574 | $(430,434) | $55,651 | $933,791 | | Crude oil | Year Ended December 31, 2022 | Price Variance | Volume Variance | 2023 | | --- | ---: | ---: | ---: | ---: | | Price (per bbl) | $87.79 | $(20.50) | $— | $67.29 | | Production (Mbbls) | 2,716 | — | (241) | 2,475 | | **Crude oil sales** | $238,407 | $(50,742) | $(21,103) | $166,562 | | Consolidated | Year Ended December 31, 2022 | Price Variance | Volume Variance | 2023 | | --- | ---: | ---: | ---: | ---: | | Price (per mcfe) | $6.34 | $(3.35) | $— | $2.99 | | Production (Mmcfe) | 774,089 | — | 6,486 | 780,575 | | **Total natural gas, NGLs and oil sales** | $4,911,092 | $(2,617,579) | $41,148 | $2,334,661 | ***Transportation, gathering, processing and compression*** expense was $1.1 billion in 2023 and $1.2 billion in 2022. These third-party costs are lower than the prior year due to lower fuel and lower electricity costs along with the impact of lower NGLs prices which results in lower processing costs. We have included these costs in the calculation of average realized prices (including all derivative settlements and third-party transportation expenses paid by Range). The following table summarizes transportation, gathering, processing and compression expense for the last two years (in thousands) and on a per mcf and per barrel basis: | Transportation, gathering, processing and compression | Year Ended December 31, 2023 | 2022 | Change | % Change | | --- | ---: | ---: | ---: | ---: | | Natural gas | $588,970 | $677,316 | $(88,346) | (13%) | | NGLs | 524,114 | 565,614 | (41,500) | (7%) | | Oil | 857 | 11 | 846 | 7,691% | | Total | $1,113,941 | $1,242,941 | $(129,000) | (10%) | | Natural gas (per mcf) | $1.09 | $1.26 | $(0.17) | (13%) | | NGLs (per bbl) | $13.81 | $15.54 | $(1.73) | (11%) | | Oil (per bbl) | $0.35 | $— | $0.35 | 100% | 42 ***Derivative fair value income (loss)*** was a gain of $821.2 million in 2023 compared to a loss of $1.2 billion in 2022. All of our derivatives are accounted for using the mark-to-market accounting method. Mark-to-market accounting treatment creates volatility in our revenues as unrealized gains and losses from derivatives are included in total revenues. As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our derivatives. Gains on our derivatives generally indicate lower wellhead revenues in the future while losses indicate higher future wellhead revenues. At December 31, 2023, our commodity derivative contracts were recorded at their fair value, which was a net derivative asset of $424.4 million, an increase of $563.0 million from the $138.6 million net derivative liability recorded as of December 31, 2022. We have also entered into basis swap agreements to limit volatility caused by changing differentials between NYMEX and regional prices received. These basis swaps are marked to market and we recognized a net derivative asset of $18.3 million as of December 31, 2023 compared to a net derivative asset of $521,000 as of December 31, 2022. The following table summarizes the impact of our commodity derivatives for the last two years (in thousands): | | Year Ended December 31, 2023 | 2022 | | --- | ---: | ---: | | **Derivative fair value income (loss) per consolidated statements of income** | $821,154 | $(1,188,506) | | **Non-cash fair value income (loss): (1)** | | | | Natural gas derivatives | $557,419 | $(2,392) | | Oil derivatives | 23,301 | 14,783 | | NGLs derivatives | — | 2,931 | | Freight derivatives | — | (114) | | Contingent consideration | (13,080) | (13,560) | | Total non-cash fair value income (loss) (1) | $567,640 | $1,648 | | **Net cash receipt (payment) on derivative settlements:** | | | | Natural gas derivatives | $256,693 | $(1,119,940) | | Oil derivatives | (11,179) | (82,546) | | NGLs derivatives | — | (12,168) | | Contingent consideration | 8,000 | 24,500 | | Total net cash receipt (payment) | $253,514 | $(1,190,154) | (1) Non-cash fair value adjustments on commodity derivatives is a non-GAAP measure. Non-cash fair value adjustments on commodity derivatives only represent the net change between periods of the fair market values of commodity derivative positions and exclude the impact of settlements on commodity derivatives during the period. We believe that non-cash fair value adjustments on commodity derivatives is a useful supplemental disclosure to differentiate non-cash fair market value adjustments from settlements on commodity derivatives during the period. Non-cash fair value adjustments on commodity derivatives is not a measure of financial or operating performance under GAAP, nor should it be considered a substitute for derivative fair value income or loss as reported in our consolidated statements of income. ***Brokered natural gas, marketing and other*** revenue was $218.6 million in 2023 compared to $424.2 million in 2022. We enter into purchase transactions with third parties and separate sale transactions with third parties at different times to utilize available pipeline capacity and to fulfill sales commitments in the event of operational upsets. The 2023 period includes $195.7 million of revenue from the sale of natural gas that is not related to our production (brokered) and $1.8 million of revenue from the sale of NGLs that is not related to our production, the receipt of $5.1 million in make-whole payments and $5.9 million of interest income. The 2022 period includes $408.6 million of revenue from the brokered sale of natural gas and $2.8 million of revenue from the sale of NGLs that is not related to our production and $2.5 million of interest income. These brokered revenues decreased compared to 2022 due to lower sales prices partially offset by higher brokered volumes. ### Costs and Expenses per mcfe We believe some of our expense fluctuations are best analyzed on a unit-of-production, or per mcfe, basis. The following presents information about certain of our expenses on a per mcfe basis for the last two years: | | Year Ended December 31, 2023 | 2022 | Change | % Change | | --- | ---: | ---: | ---: | ---: | | Direct operating expense | $0.12 | $0.11 | $0.01 | 9% | | Taxes other than income expense | 0.03 | 0.05 | (0.02) | (40%) | | General and administrative expense | 0.21 | 0.22 | (0.01) | (5%) | | Interest expense | 0.16 | 0.21 | (0.05) | (24%) | | Depletion, depreciation and amortization expense | 0.45 | 0.46 | (0.01) | (2%) | 43 ***Direct operating*** expense was $96.1 million in 2023 compared to $84.3 million in 2022. Direct operating expenses include normally recurring expenses to operate and produce our wells, non-recurring workover and repair-related expenses. On an absolute dollar basis, our direct operating expenses for 2023 increased 14% from the prior year primarily due to higher water hauling/handling costs, higher labor costs and higher workover costs. We incurred $4.5 million of workover costs in 2023 compared to $3.0 million of workover costs in 2022. On a per mcfe basis, operating expense for 2023 increased $0.01, or 9% from the same period of 2022, with the increase due to higher workover costs. Stock-based compensation expense represents the amortization of equity grants as part of the compensation of field employees. The following table summarizes direct operating expenses per mcfe for the last two years: | Direct operating | Year Ended December 31, 2023 | 2022 | Change | % Change | | --- | ---: | ---: | ---: | ---: | | Lease operating expense | $0.11 | $0.11 | $— | —% | | Workovers | 0.01 | — | 0.01 | 100% | | Stock-based compensation | — | — | — | —% | | Total direct operating expense | $0.12 | $0.11 | $0.01 | 9% | ***Taxes other than income*** expense was $23.7 million in 2023 compared to $35.4 million in 2022. This expense category is primarily the Pennsylvania impact fee. In 2012, Pennsylvania enacted an "impact fee" on unconventional natural gas and oil production which includes the Marcellus Shale. The impact fee is based upon the year wells are drilled and the fee varies, like a severance tax, based upon natural gas prices. The year ended December 31, 2023 includes a $21.8 million impact fee compared to $33.2 million in the year ended December 31, 2022, with the decrease primarily due to lower natural gas prices. This category also includes other taxes such as franchise, real estate and commercial activity taxes. The following table summarizes taxes other than income per mcfe for the last two years: | Taxes other than income | Year Ended December 31, 2023 | 2022 | Change | % Change | | --- | ---: | ---: | ---: | ---: | | Impact fee | $0.03 | $0.04 | $(0.01) | (25%) | | Other | — | 0.01 | (0.01) | (100%) | | Total taxes other than income | $0.03 | $0.05 | $(0.02) | (40%) | ***General and administrative*** expense was $164.7 million for 2023 compared to $168.1 million for 2022. The decrease in 2023, when compared to 2022, is primarily due to lower stock-based compensation and lower legal expenses partially offset by higher salaries and benefit costs. As of December 31, 2023, the number of general and administrative employees was the same when compared to December 31, 2022. On a per mcfe basis, general and administrative expense for 2023 was 5% lower when compared to the same period of 2022 due to lower stock-based compensation. Stock-based compensation expense represents the amortization of stock-based compensation awards granted to our employees and our non-employee directors as part of their compensation. The following table summarizes general and administrative expenses per mcfe for the last two years: | General and administrative | Year Ended December 31, 2023 | 2022 | Change | % Change | | --- | ---: | ---: | ---: | ---: | | General and administrative | $0.16 | $0.16 | $— | —% | | Stock-based compensation | 0.05 | 0.06 | (0.01) | (17%) | | Total general and administrative expense | $0.21 | $0.22 | $(0.01) | (5%) | 44 ***Interest expense*** was $124.0 million for 2023 compared to $165.1 million for 2022. The following table summarizes interest expense per mcfe for the last two years: | | Year Ended December 31, 2023 | 2022 | Change | % Change | | --- | ---: | ---: | ---: | ---: | | Bank credit facility | $0.01 | $0.01 | $— | —% | | Senior notes | 0.14 | 0.19 | (0.05) | (26%) | | Amortization of deferred financing costs and other | 0.01 | 0.01 | — | —% | | Total interest expense | $0.16 | $0.21 | $(0.05) | (24%) | | Average debt outstanding (in thousands) | $1,821,940 | $2,510,107 | $(688,167) | (27%) | | Average interest rate (a) | 6.5% | 6.25% | 0.25% | 4% | (a) Includes commitment fees but excludes amortization of debt issue costs. On an absolute basis, the decrease in interest expense for 2023 from 2022 was primarily due to lower overall outstanding average debt balances. See Note 6 to our consolidated financial statements for additional information. Average debt outstanding on the bank credit facility for 2023 was $8.0 million compared to $48.4 million for 2022 and the weighted average interest rate on the bank credit facility was 8.4% for 2023 compared to 4.1% in 2022. ***Depletion, depreciation and amortization*** ("DD&A") was $350.2 million in 2023 compared to $353.4 million in 2022. The decrease in 2023 when compared to 2022 is due to a 2% decrease in depletion rates. On a per mcfe basis, DD&A decreased to $0.45 in 2023 compared to $0.46 in 2022. Depletion expense, the largest component of DD&A, was $0.44 per mcfe in 2023 compared to $0.45 per mcfe in 2022. We have historically adjusted our depletion rates in the fourth quarter of each year based on our year-end reserve report and at other times during the year when circumstances indicate there has been a significant change in reserves or costs. The following table summarizes DD&A expenses per mcfe for the last two years: | DD&A | Year Ended December 31, 2023 | 2022 | Change | % Change | | --- | ---: | ---: | ---: | ---: | | Depletion and amortization | $0.44 | $0.45 | $(0.01) | (2%) | | Accretion and other | 0.01 | 0.01 | — | —% | | Total DD&A expenses | $0.45 | $0.46 | $(0.01) | (2%) | ### Other Operating Expenses Our total operating expenses also include other expenses that generally do not trend with production. These expenses include stock-based compensation, brokered natural gas and marketing, exploration expense, abandonment and impairment of unproved properties, exit costs, deferred compensation plan and gain or loss on early extinguishment of debt. The following table details stock-based compensation that is allocated to functional expense categories for the last two years (in thousands): | | 2023 | 2022 | | --- | ---: | ---: | | Direct operating expense | $1,723 | $1,459 | | Brokered natural gas and marketing expense | 2,095 | 2,439 | | Exploration expense | 1,250 | 1,578 | | General and administrative expense | 35,850 | 42,023 | | Total stock-based compensation | $40,918 | $47,499 | Stock-based compensation includes the amortization of restricted stock and performance-based grants. ***Brokered natural gas and marketing*** expense was $202.9 million in 2023 compared to $427.0 million in 2022. We enter into purchase transactions with third parties and separate sale transactions with third parties at different times to utilize available pipeline capacity and fulfill sales commitments in the event of operational upsets. The decrease in these costs reflects lower purchase prices partially offset by higher purchased volumes. The following table details our brokered natural gas, marketing and other net margin which includes the net effect of these third-party transactions for the two-year period ended December 31, 2023 (in thousands): | Brokered natural gas and marketing | 2023 | 2022 | | --- | ---: | ---: | | Brokered natural gas sales | $195,656 | $408,584 | | Brokered NGLs sales | 1,834 | 2,783 | | Interest income | 5,937 | 2,538 | | Other marketing revenue and other income | 15,176 | 10,312 | | Brokered natural gas purchases and transportation | (191,659) | (413,911) | | Brokered NGLs purchases | (1,632) | (2,808) | | Other marketing expense | (9,593) | (10,329) | | Net brokered natural gas and marketing margin | $15,719 | $(2,831) | ***Exploration*** expense was $26.5 million in 2023 compared to $26.8 million in 2022. Exploration expense in 2023 was lower when compared to the prior year with lower delay rentals partially offset by higher seismic and personnel costs. Stock-based compensation represents the amortization of equity stock grants as part of the compensation of our exploration staff. The following table details our exploration related expenses for the last two years (in thousands): | Exploration | Year Ended December 31, 2023 | 2022 | Change | % Change | | --- | ---: | ---: | ---: | ---: | | Seismic | $1,687 | $237 | $1,450 | 612% | | Delay rentals and other | 17,644 | 19,576 | (1,932) | (10%) | | Personnel expense | 5,949 | 5,381 | 568 | 11% | | Stock-based compensation expense | 1,250 | 1,578 | (328) | (21%) | | Total exploration expense | $26,530 | $26,772 | $(242) | (1%) | ***Abandonment and impairment of unproved properties*** was $46.4 million in 2023 compared to $28.6 million in 2022. These costs increased when compared to the same period of 2022 due to higher estimated lease expirations in Pennsylvania. Impairment of individually insignificant unproved properties is assessed and amortized on an aggregate basis based on our average holding period, expected forfeiture rate and anticipated drilling success. We assess individually significant unproved properties for impairment on a quarterly basis and recognize a loss where circumstances indicate impairment in value. In determining whether a significant unproved property is impaired we consider numerous factors including, but not limited to, current exploration plans, favorable or unfavorable activity on the property being evaluated and/or adjacent properties, our geologists’ evaluation of the property and the remaining months in the lease term for the property. ***Exit costs*** in 2023 were $99.9 million compared to $70.3 million in 2022. In August 2020, we completed the sale of our North Louisiana operations in a transaction that included the retention of certain related gathering, transportation and processing obligations extending until 2030. The present value of these estimated future obligations totaled $479.8 million which was recorded in third quarter 2020. In the twelve months ended December 31, 2023, we recorded $41.9 million accretion expense related to these retained liabilities and in second quarter 2023, we recorded an adjustment of $37.8 million to increase this obligation for an increase in forecasted rates due to inflation. In addition, in fourth quarter 2023, we recorded an additional $18.0 million adjustment to increase the obligation for a change to our forecasted drilling plans of the buyer. In the twelve months ended December 31, 2022, we recorded $43.6 million accretion expense related to these retained liabilities and we recorded an adjustment of $24.8 million to increase this obligation for a change in forecasted drilling plans of the buyer and other adjustments. The following table details our exit costs for the last two years (in thousands): | Exit costs | Year Ended December 31, 2023 | 2022 | | --- | ---: | ---: | | Divestiture contract obligation (including accretion of discount) | $99,595 | $69,758 | | Transportation contract capacity releases (including accretion of discount) | 345 | 579 | | Total exit costs | $99,940 | $70,337 | 46 ***Deferred compensation plan*** expense was $26.6 million in 2023 compared to $61.9 million in 2022. Our stock price increased to $30.44 at December 31, 2023 from $25.02 at December 31, 2022. This non-cash item relates to the increase or decrease in value of the liability associated with our common stock that is vested and held in our deferred compensation plan. The deferred compensation liability is adjusted to fair value by a charge or a credit to deferred compensation plan expense. Common shares are placed in the deferred compensation plan when granted to eligible participants. The deferred compensation plan held 1.5 million vested shares at December 31, 2023 compared to 5.3 million shares at December 31, 2022. ***Gain (loss) on early extinguishment of debt*** was a gain of $438,000 in 2023 compared to a loss of $69.5 million in 2022. In second quarter 2023, we purchased on the open market $61.6 million principal amount of 4.875% senior notes due 2025 at a discount and recorded a gain of $438,000, net of transaction costs and the expensing of deferred financing costs on the repurchased debt. In first quarter 2022, we announced a call for the redemption of $850.0 million of our outstanding 9.25% senior notes due 2026 which were redeemed on February 1, 2022. The redemption price equaled 106.938% of par plus accrued and unpaid interest. We recognized a loss on early extinguishment of debt of $69.2 million. ***Income tax expense*** was $229.2 million in 2023 compared to $230.5 million in 2022. Income tax expense was the same as the prior year with lower operating income offset by the impact of changes in our valuation allowances each year. The following is a summary of income tax expense (in thousands): | Income tax expense | Year Ended December 31, 2023 | 2022 | | --- | ---: | ---: | | Current tax expense | $1,547 | $14,688 | | Deferred income tax expense | 227,654 | 215,772 | | Total income tax expense | $229,201 | $230,460 | | Combined federal and state effective income tax rate | 20.8% | 16.3% | See Note 4 to our consolidated financial statements for further detail. ### Management’s Discussion and Analysis of Financial Condition, Cash Flows, Capital Resources and Liquidity Commodity prices are the most significant factor impacting our revenues, net income, operating cash flows, the amount of capital we invest in our business, payment of dividends and funding of share repurchases. Commodity prices have been and are expected to remain volatile. Our top priorities for using cash provided by operations are to fund our capital budget program, debt repayments and return capital to stockholders. We currently believe we have sufficient liquidity and capital resources to execute our business plan for the foreseeable future and across a wide range of commodity price environments. ### Cash Flows The following table presents sources and uses of cash and cash equivalents for the last two years (in thousands): | Sources of cash and cash equivalents | 2023 | 2022 | | --- | ---: | ---: | | Operating activities | $977,892 | $1,864,744 | | Disposal of assets | 872 | 518 | | Borrowing on credit facility | 185,000 | 972,000 | | Issuance of new senior notes | — | 500,000 | | Other | 124,722 | 72,713 | | **Total sources of cash and cash equivalents** | $1,288,486 | $3,409,975 | | **Uses of cash and cash equivalents** | | | | Additions to natural gas and oil properties | $(571,819) | $(456,505) | | Acreage purchases | (34,410) | (30,885) | | Other property | (701) | (682) | | Repayments on credit facility | (204,000) | (953,000) | | Repayment of senior notes | (60,934) | (1,659,422) | | Purchases of treasury stock | (19,042) | (399,699) | | Dividends paid | (77,241) | (38,638) | | Other | (108,572) | (85,359) | | **Total uses of cash and cash equivalents** | $(1,076,719) | $(3,624,190) | 47 #### Sources of Cash and Cash Equivalents ***Cash flow from operating activities*** in 2023 was $977.9 million compared to $1.9 billion in 2022. Cash provided from operating activities is largely dependent upon commodity prices and production volumes, net of the effects of settlement of our derivative contracts. The decrease in cash provided from operating activities in 2023 from 2022 reflects significantly lower realized prices partially offset by the impact of a favorable change in working capital outflow (the timing of cash receipts and disbursements). As of December 31, 2023, we have hedged more than 45% of our projected total production for 2024 with more than 50% of our projected natural gas production hedged. Net cash provided from operating activities is also affected by working capital changes or the timing of cash receipts and disbursements. Changes in working capital (as reflected in our consolidated statements of cash flows) for 2023 was an outflow of $121.1 million compared to an outflow of $169.3 million for 2022. #### Uses of Cash and Cash Equivalents ***Additions to natural gas and oil properties*** are our most significant use of cash and cash equivalents. These cash outlays are associated with our drilling and completion capital budget program. The following table shows capital expenditures and reconciles to additions to natural gas and oil properties as presented on our consolidated statements of cash flows for the last two years (in thousands): | | 2023 | 2022 | | --- | ---: | ---: | | Appalachia | $571,607 | $462,134 | | Change in capital expenditure accrual for proved properties | 1,204 | (4,116) | | Change in other non-cash capital expenditures | (992) | (1,513) | | **Additions to natural gas and oil properties** | $571,819 | $456,505 | ***Repayment of senior notes*** for 2023 includes the repurchase of $61.6 million principal of our 4.875% senior notes due 2025, at a discount. ***Purchases of treasury stock*** for 2023 include the repurchase of 715,000 shares of common stock for a total of $19.0 million as part of our previously announced stock repurchase program. ### Liquidity and Capital Resources Our main sources of liquidity are cash, internally generated cash flow from operations, capital market transactions and our bank credit facility. At December 31, 2023, we had approximately $1.5 billion of liquidity consisting of cash on hand and availability under our bank credit facility. Our liquidity requirements are supported by our cash on hand and our bank credit facility. We may draw on our bank credit facility to meet short-term cash requirements or issue debt or equity securities through the shelf registration discussed below as part of our longer-term liquidity and capital management. We believe our short-term and long-term liquidity is adequate to fund our current operations and our near-term and long-term funding requirements including our capital spending programs, repayment of debt maturities and dividends. Although we expect cash flows to be sufficient to fund our expected 2024 capital program, we may elect to use the bank credit facility or raise funds through new debt or equity offerings or from other sources of financing. ### Bank Credit Facility Our bank credit facility is secured by substantially all of our assets. In April 2022, we entered into an amended bank credit facility with a maturity date of April 14, 2027. As of December 31, 2023, we had no outstanding borrowings under our bank credit facility and we maintain a borrowing base of $3.0 billion and aggregate lender commitments of $1.5 billion. We also have undrawn letters of credit of $173.4 million as of December 31, 2023 which reduce the borrowing capacity under our bank credit facility. The borrowing base is subject to regular, semi-annual redeterminations and is dependent on a number of factors but primarily the lender’s assessment of future cash flows. The next scheduled borrowing base redetermination is during the spring of 2024. We currently must comply with certain financial and non-financial covenants, including limiting dividend payments, debt incurrence and requirements that we maintain certain financial ratios (as defined in our bank credit agreement). We were in compliance with all such covenants at December 31, 2023. See Note 6 to our consolidated financial statements for more information. ### Capital Requirements Our material cash requirements include the following contractual and other potential or expected obligations: ### Capital Budget Our approved capital budget for 2024 is $620 million to $670 million. The amount of our future capital expenditures will depend upon a number of factors including our cash flows from operations, investing and financing activities, infrastructure availability, supply and demand fundamentals and our ability to execute our development program. We periodically review our budget to assess changes in current and projected cash flows, debt requirements and other factors. ### Long-Term Debt As of December 31, 2023, we had $1.8 billion of total long-term debt outstanding. Our next significant long-term debt maturity is in the amount of $688.4 million due 2025. Anticipated cash annual interest payments related to our fixed-rate debt, based on the amount outstanding at December 31, 2023, is $23.8 million on our 4.75% senior notes, $33.6 million on our 4.875% senior notes and $49.5 million on our 8.25% senior notes. ### Stock Repurchase Program Our total remaining share repurchase authorization was approximately $1.1 billion at December 31, 2023. ### Other Sources of Liquidity We have a universal shelf registration statement filed with the SEC under which we, as a "well-known seasoned issuer" for purposes of SEC rules, have the ability to sell an indeterminate amount of various types of debt and equity securities. ### Cash Contractual Obligations Our contractual obligations include long-term debt, operating leases, derivative obligations, asset retirement obligations and transportation, gathering and processing commitments. As of December 31, 2023, we do not have any capital leases or any significant off-balance sheet debt or other such unrecorded obligations and we have not guaranteed any debt of any unrelated party. As of December 31, 2023, we had a total of $173.4 million of letters of credit outstanding under our bank credit facility. The table below provides estimates of the timing of future payments that we are obligated to make based on agreements in place at December 31, 2023. In addition to the contractual obligations listed in the table below, our consolidated balance sheet at December 31, 2023 reflects accrued interest payable on our bank debt of $41,000, which is payable in first quarter 2024. The following summarizes our contractual financial obligations at December 31, 2023 and their future maturities. We expect to fund these contractual obligations with cash generated from operating activities, and, if necessary, borrowings under our bank credit facility or other sources (in thousands): | Debt: | Payment due by period 2024 | 2025 | 2026 | 2027 and 2028 | Thereafter | Total | | --- | ---: | ---: | ---: | ---: | ---: | ---: | | Bank debt due 2027 (a) | $— | $— | $— | $— | $— | $— | | 4.875% senior notes due 2025 | — | 688,388 | — | — | — | 688,388 | | 8.25% senior notes due 2029 | — | — | — | — | 600,000 | 600,000 | | 4.75% senior notes due 2030 | — | — | — | — | 500,000 | 500,000 | | Other obligations: | | | | | | — | | Operating leases | 13,119 | 7,921 | 6,866 | 2,698 | 29 | 30,633 | | Software licenses and other | 2,117 | 576 | 279 | 16 | — | 2,988 | | Derivative obligations (b) | 222 | 107 | — | — | — | 329 | | Transportation and gathering commitments (c) | 801,694 | 730,907 | 670,692 | 616,260 | 3,070,613 | 5,890,166 | | Asset retirement obligation liability (d) | 2,395 | 38 | — | — | 114,996 | 117,429 | | Total contractual obligations (e) | $819,547 | $1,427,937 | $677,837 | $618,974 | $4,285,638 | $7,829,933 | (a) We had no outstanding balance as of the end of the year. (b) Derivative obligations represent net liabilities determined in accordance with master netting arrangements for commodity derivatives that were valued as of December 31, 2023. Our derivatives are measured and recorded at fair value and are subject to market and credit risk. The ultimate liquidation value will be dependent upon actual future commodity prices which may differ materially from the inputs used to determine fair value as of December 31, 2023. See Note 8 to our consolidated financial statements. (c) The obligations above represent our minimum financial commitments pursuant to the terms of these contracts. Our actual expenditures may exceed these minimum commitments. (d) The amount above represents the discounted values. There are inherent uncertainties surrounding the obligations and the actual amount and timing may differ from our estimates. See Note 7 to our consolidated financial statements. (e) This table excludes the liability for the deferred compensation plans since these obligations will be funded with existing plan assets and does not include obligations to taxing authorities. 49 We have also entered into an additional agreement which modifies existing contracts that are included in the cash contractual obligation table above but is contingent on additional facility construction and is expected to begin in 2024 with a twelve-year term and adds to our ability to efficiently flow production volumes. The revised agreement covers volumes of 650,000 mcf per day but declines in the last five years of the contract ending at 300,000 mcf per day. Not included in the table above is our estimate of accrued contractual obligations related to certain obligations retained by us after our divestiture of our North Louisiana assets in 2020. These contractual obligations are related to gathering, processing and transportation agreements including certain minimum volume commitments. There are inherent uncertainties surrounding the retained obligation and, as a result, the determination of the accrued obligation required significant judgment and estimation. The actual settlement amount and timing may differ from our estimates. See also Note 13 and Note 14 to our consolidated financial statements. As of December 31, 2023, the carrying value of this obligation was $397.4 million (discounted) and is included in divestiture contract obligation in our consolidated balance sheets. As of December 31, 2023, our estimated settlement of this retained obligation based on a discounted value is as follows (in thousands): | | Year Ended December 31, | | --- | ---: | | 2024 | $86,762 | | 2025 | 77,418 | | 2026 | 61,805 | | 2027 | 52,622 | | 2028 | 48,116 | | Thereafter | 70,727 | | | $397,450 | ### Income Taxes We are subject to income and non-income-based taxes under federal, state and local jurisdictions in which we operate. Historically, we have generated and carried forward net operating losses ("NOL") in amounts sufficient to offset all our taxable income at the federal level. To the extent we utilize all or substantially all of our federal NOL carryovers, we expect to begin to make federal income tax payments. In addition, the Inflation Reduction Act of 2022 could trigger minimum income taxes if we become subject to the corporate alternative minimum tax where we may have to make estimated federal income tax payments. We currently pay state income taxes in the Commonwealth of Pennsylvania. See Note 4 to our consolidated financial statements for more information. ### Proved Reserves To maintain and grow production and cash flow, we must continue to develop existing proved reserves and locate or acquire new natural gas, NGLs and oil reserves. The following is a discussion of proved reserves, reserve additions and revisions and future net cash flows from proved reserves. | Proved Reserves: | Year End December 31, 2023 (Mmcfe) | 2022 | | --- | ---: | ---: | | Beginning of year | 18,077,656 | 17,775,484 | | Reserve revisions | 608,784 | (591,983) | | Reserve extensions, discoveries and additions | 207,260 | 1,668,244 | | Production | (780,575) | (774,089) | | End of year | 18,113,125 | 18,077,656 | | **Proved Developed Reserves:** | | | | Beginning of year | 10,933,180 | 10,417,887 | | End of year | 11,535,852 | 10,933,180 | Our proved reserves at year-end 2023 were 18.1 Tcfe which were slightly higher than year-end 2022. Natural gas comprised approximately 64% of our proved reserves at year-end 2023. *Reserve Revisions and Additions.* Revisions of previous estimates of a positive 608.8 Bcfe includes a positive revision of 280.2 Bcfe for previously undeveloped properties reclassified from non-proved properties due to their addition to our five-year development plan and positive performance revisions of 701.4 Bcfe due to improved well performance and longer lateral lengths partially offset by negative pricing revisions and 370.6 Bcfe reclassified to unproved for previously planned wells not to be drilled within the original five-year development horizon. We added 207.3 Bcfe of proved reserves from drilling activities and evaluation of proved areas in Pennsylvania. Our ethane reserves are intended to match volumes delivered under our existing long-term, extendable contracts along with meeting pipeline specifications. During 2022, we added 1.7 Tcfe of proved reserves from drilling activities and evaluation of proved areas in Pennsylvania. Approximately 77% of the 2022 reserve additions are attributable to natural gas. Our ethane reserves are intended to match volumes delivered under our existing long-term, extendable contracts. Revisions of previous estimates of a negative 592.0 Bcfe includes 1.4 Tcfe reserves reclassified to unproved because of previously planned wells not expected to be drilled within the original five year development horizon significantly offset by favorable pricing revisions, positive performance revisions of 72.8 Bcfe and 716.2 Bcfe for previously proved undeveloped properties as they were added back to our five-year development plan. Wells reclassified to unproved during the year are the result of the out-performance of existing wells which resulted in a higher utilization of in-field gathering capacity and a reallocation of capital due to the drilling of longer laterals on existing locations. *Future Net Cash Flows.* At December 31, 2023, the present value (discounted at 10%) of estimated future net cash flows from our proved reserves was $7.9 billion. The present value of our estimated future net cash flows at December 31, 2022 was $29.6 billion. This present value was calculated based on the unweighted average first-day-of-the-month oil and gas prices for the prior twelve months held flat for the life of the reserves, in accordance with SEC rules. At December 31, 2023, the after-tax present value of estimated future net cash flows from our proved reserves was $6.8 billion compared to $24.5 billion at December 31, 2022. The present value of future net cash flows does not purport to be an estimate of the fair market value of our proved reserves. An estimate of fair value would also take into account, among other things, anticipated changes in future prices and costs, the expected recovery of reserves in excess of proved reserves and a discount factor more representative of the time value of money to the evaluating party and the perceived risks inherent in producing oil and gas. ### Delivery Commitments We have various volume delivery commitments that are related to our Marcellus Shale properties. We expect to be able to fulfill our contractual obligations from our own production; however, we may purchase third-party volumes to satisfy our commitments or pay demand fees for commitment shortfalls, should they occur. As of December 31, 2023, our delivery commitments through 2037 were as follows: | Year Ending December 31, | Natural Gas (mmbtu per day) | Ethane and Propane (bbls per day) | | --- | ---: | ---: | | 2024 | 302,404 | 70,000 | | 2025 | 282,493 | 54,932 | | 2026 | 200,548 | 50,000 | | 2027 | 100,000 | 46,233 | | 2028 | 100,000 | 45,000 | | 2029 | 100,000 | 33,444 | | 2030 | - | 30,000 | | 2031 | - | 16,575 | | 2032 - 2037 | - | 10,000 (each year) | ### Other We lease acreage that is generally subject to lease expiration if initial wells are not drilled within a specified period, generally between three and five years. We do not expect to lose significant lease acreage because of failure to drill due to inadequate capital, equipment or personnel. However, based on our evaluation of prospective economics, including the cost of infrastructure to connect production, we have allowed acreage to expire and will allow additional acreage to expire in the future. To date, our expenditures to comply with environmental or safety regulations have not been a significant component of our cost structure and are not expected to be significant in the future. However, new regulations, enforcement policies, claims for damages, or other events could result in significant future costs. We also regularly provide letters of credit in the normal course of business under certain contracts that may be drawn if we fail to perform under those contracts. ### Off-Balance Sheet Arrangements We do not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance our liquidity or capital resources position. However, as is customary in the natural gas and oil industry, we have various contractual work commitments which are described above under cash contractual obligations. ### Management’s Discussion of Critical Accounting Estimates Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at year-end and the reported amounts of revenues and expenses during the year. Accounting estimates are considered to be critical if (1) the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to changes; and (2) the impact of the estimates and assumptions on financial condition or operating performance is material. Actual results could differ from the estimates and assumptions used. ### Estimated Quantities of Net Reserves We use the successful efforts method of accounting for natural gas and oil producing activities as opposed to the alternate acceptable full cost method. We believe that net assets and net income are more conservatively measured under the successful efforts method of accounting than under the full cost method, particularly during periods of active exploration. One difference between the successful efforts method of accounting and the full cost method is that under the successful efforts method, all exploratory dry holes and geological and geophysical costs are charged against earnings during the periods they occur; whereas, under the full cost method of accounting, such costs are capitalized as assets, pooled with the costs of successful wells and charged against earnings of future periods as a component of depletion expense. Under the successful efforts method of accounting, successful exploration drilling costs and all development costs are capitalized and these costs are systematically charged to expense using the units of production method based on proved developed natural gas and oil reserves as estimated by our engineers and audited by independent engineers. Costs incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized on our balance sheet if (1) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (2) we are making sufficient progress assessing the reserves and the economic and operating viability of the project. Proven property leasehold costs are amortized to expense using the units of production method based on total proved reserves. Properties are assessed for impairment as circumstances warrant (at least annually) and impairments to value are charged to expense. The successful efforts method inherently relies upon the estimation of proved reserves, which includes proved developed and proved undeveloped volumes. Proved reserves are defined by the SEC as those volumes of natural gas, NGLs, condensate and crude oil that geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are volumes expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves include reserves for which a development plan has been adopted indicating each location is scheduled to be drilled within five years from the date it was booked as proved reserves, unless specific circumstances justify a longer time. Although our engineers are knowledgeable of and follow the guidelines for reserves established by the SEC, the estimation of reserves requires engineers to make a significant number of assumptions based on professional judgment. Reserve estimates are updated at least annually and consider recent production levels and other technical information. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information, including reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price and cost changes and other economic factors. Changes in natural gas, NGLs and oil prices can lead to a decision to start up or shut in production, which can lead to revisions to reserve quantities. Reserve revisions in turn cause adjustments in our depletion rates. We cannot predict what reserve revisions may be required in future periods. Reserve estimates are reviewed and approved by our Senior Vice President of Reservoir Engineering and Economics, who reports directly to our President and Chief Executive Officer. To further ensure the reliability of our reserve estimates, we engage independent petroleum consultants to audit our estimates of proved reserves. Estimates prepared by third parties may be higher or lower than those included herein. Independent petroleum consultants audited approximately 96% of our reserves in both 2023 and 2022. Historical variances between our reserve estimates and the aggregate estimates of our consultants have been approximately 5%. The reserves included in this report are those reserves estimated by our petroleum engineering staff. For additional discussion, see Items 1 & 2. Business and Properties – *Proved Reserves.* Reserves are based on the weighted average of commodity prices during the 12-month period, using the closing prices on the first day of each month, as defined by the SEC. When determining the December 31, 2023 proved reserves for each property, benchmark prices are adjusted using price differentials that account for property-specific quality and location differences. If prices in the future average below prices used to determine reserves at December 31, 2023, it could have an adverse effect on our estimates of proved reserves. It is difficult to estimate the magnitude of any potential price change and the effect on proved reserves due to numerous factors (including commodity prices and performance revisions). Depletion rates are determined based on reserve quantity estimates and the capitalized costs of producing properties. As the estimated reserves are adjusted, the depletion expense for a property will change, assuming no change in production volumes or the capitalized costs. While total depletion expense for the life of a property is limited to the property’s total cost, proved reserve revisions result in a change in the timing of when depletion expense is recognized. Downward revisions of proved reserves may result in an acceleration of depletion expense, while upward revisions tend to lower the rate of depletion expense recognition. Based on proved reserves at December 31, 2023, we estimate that a 1% change in proved reserves would increase or decrease 2024 depletion expense by approximately $3.0 million (based on current production estimates). We currently expect our DD&A rate to be approximately $0.44 per mcfe in 2024. Estimated reserves are used as the basis for calculating the expected future cash flows from property asset groups, which are used to determine whether that property may be impaired. Reserves are also used to estimate the supplemental disclosure of the standardized measure of discounted future net cash flows relating to natural gas and oil producing activities and reserve quantities in Note 15 to our consolidated financial statements. Changes in the estimated reserves are considered a change in estimate for accounting purposes and are reflected on a prospective basis. It should not be assumed that the standardized measure is the current market value of our estimated proved reserves. ### Fair Value Estimates Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. There are three approaches for measuring the fair value of assets and liabilities: the market approach, the income approach and the cost approach, each of which includes multiple valuation techniques. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single present value, or range of present values, using current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an asset. This is often referred to as current replacement cost. The cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence. The fair value accounting standards do not prescribe which valuation technique should be used when measuring fair value and do not prioritize among the techniques. These standards establish a fair value hierarchy that prioritizes the inputs used in applying the various valuation techniques. Inputs broadly refer to the assumptions that market participants use to make pricing decisions, including assumptions about risk. Level 1 inputs are given the highest priority in the fair value hierarchy, while Level 3 inputs are given the lowest priority. The three levels of the fair value hierarchy are as follows: - Level 1-Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. - Level 2-Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the measurement date. - Level 3-Unobservable inputs for which there is little, if any, market activity for the asset or liability being measured. These inputs reflect management’s best estimates of the assumptions market participants would use in determining fair value. Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. See Note 9 to the consolidated financial statements for disclosures regarding our fair value measurements. The need to test long-lived assets for impairment can be based on several indicators, including reductions in commodity prices, reductions to our capital budget, unfavorable adjustments to reserves, significant changes in the expected timing of production, other changes to contracts or changes in the regulatory environment in which a property is located. Valuation methods used to measure fair value may require significant management judgement and estimates to derive the inputs necessary to determine fair value. Whenever changes in facts and circumstances indicate that the carrying value of our long-lived assets may not be recoverable, we perform an impairment evaluation. For purposes of this evaluation, long-lived assets must be grouped at the lowest level for which independent cash flows can be identified, which generally is field-by-field, in certain instances, by logical grouping of assets if there is significant shared infrastructure or contractual terms that cause economic interdependency amongst separate, discrete fields. If the sum of the undiscounted estimated cash flows from the use of the asset group and its eventual disposition is less than the carrying value of an asset group, the carrying value is written down to the estimated fair value. As of December 31, 2023, our estimated undiscounted cash flows relating to our long-lived assets significantly exceeded their carrying values. Fair value calculated for the purpose of testing our natural gas and oil properties for impairment is estimated using the present value of expected future cash flows method and comparative market prices when appropriate. Significant judgment is involved in performing these fair value estimates since the results are based on forecasted assumptions. We base our fair value estimates on projected financial information which we believe to be reasonably likely to occur. An estimate of the sensitivity to changes in assumptions in our undiscounted cash flow calculations is not practicable, given the numerous assumptions (e.g. reserves, pace and timing of development plans, commodity prices, capital expenditures, operating costs, drilling and development costs, inflation and discount rates) that can materially affect our estimates. Unfavorable adjustments to some of the above listed assumptions would likely be offset by favorable adjustments in other assumptions. For example, the impact of sustained reduced commodity prices on future undiscounted cash flows would likely be partially offset by lower costs. We record all derivative instruments at fair value. Fair value measurements are based on observable market-based inputs that are corroborated by market data and are discussed more fully in Note 8 to our consolidated financial statements and in Item 7A. Quantitative and Qualitative Disclosures About Market Risk. ### Exit Cost Estimates Our consolidated balance sheets include accrued exit cost obligations related to retained gathering, processing and transportation contracts associated with divestiture of our North Louisiana assets during 2020. Inherent in the initial fair value calculation of these exit costs were numerous assumptions and judgments including the ultimate amounts to be paid, the credit-adjusted discount rates, the development plans of the buyer and our probability weighted forecast of those drilling plans, market conditions and the ultimate usage by the buyer of each facility included in the agreement. A significant portion of this obligation is a gas processing agreement that includes a deficiency payment if the minimum volume commitment is not met and we must assess the likelihood and amount of production volumes flowing to this facility. In addition, our agreement includes additional transportation agreements that are based on contractual rates applied to a minimum volume usage. We have made significant judgments and estimates regarding the timing and amount of these liabilities. We based our initial fair value estimate on assumptions we believed to be reasonable and likely to occur. We have continued to refine our forecast of the buyer's development plans since the divestiture. Changes in other assumptions, such as the estimate of production volumes flowing to certain processing facilities, could result in a higher liability. If we assume the flow of production volumes was held flat through the end of the contract, the liability could increase by approximately $9.1 million. If the forecasted inflation rates were to increase or decrease in the amount of 1%, the difference in the liability would be $9.4 million. We continue to regularly monitor our estimates and in the future may be required to adjust our estimates based on facts and circumstances. See Note 13 and Note 14 to our consolidated financial statements for a further discussion of these costs. ### Income Taxes We are subject to income and other taxes in all areas in which we operate. For financial reporting purposes, we provide taxes at rates applicable for the appropriate tax jurisdictions. Estimates of amounts of income tax to be recorded involve interpretation of complex tax laws. Our effective tax rate is subject to variability as a result of factors other than changes in federal and state tax rates and/or changes in tax laws which could affect us. Our effective rate is also affected by changes in the allocation of revenue among states. Our consolidated balance sheets include deferred tax assets. Deferred tax assets arise when expenses are recognized in the financial statements before they are recognized in the tax returns or when income items are recognized in the tax returns before they are recognized in the financial statements. Deferred tax assets also arise when operating losses or tax credits are available to offset tax payments due in future years. Ultimately, realization of a deferred tax asset depends on the existence of sufficient taxable income within the future periods to absorb future deductible temporary differences, loss carryforwards or credits. In assessing the potential realization of deferred tax assets, management must consider whether it is more likely than not (a likelihood of more than 50%) that some portion or all of the deferred tax assets will be realized. Management considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. Such evidence includes the scheduled reversal of deferred tax liabilities, projected future taxable income, new legislation and tax planning strategies in making this assessment and judgment is required in considering the relative weight of negative and positive evidence. We continue to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforwards, credits and other deferred tax assets will be utilized prior to their expiration. As a result, we may determine that an additional deferred tax asset valuation allowance should be established. Significant judgment is involved in this determination as we are required to make assumptions about future commodity prices, projected production, development activities, profitability of future business strategies and forecasted economics in the oil and gas industry. Additionally, changes in the effective tax rate resulting from changes in tax law and our level of earnings may limit utilization of deferred tax assets and will affect valuation of deferred tax balances in the future. Changes in judgment regarding future realization of deferred tax assets may result in a reversal of all or a portion of the valuation allowance. See Note 4 to our consolidated financial statements for additional information. An estimate of the sensitivity to changes in our assumptions resulting in future income calculations is not practical, given the numerous assumptions that can materially affect our estimates. Unfavorable adjustments to some of the assumptions would likely be offset by favorable adjustments in other assumptions. For example, the impact of sustained reduced commodity prices on future taxable income would likely be partially offset by lower capital expenditures. We may be challenged by taxing authorities over the amount and/or timing of recognition of revenues and deductions in our various income tax returns. Although we believe that we have adequately provided for all taxes, income or losses could occur in the future due to changes in estimates or resolution of outstanding tax matters. ### Accounting Standards Not Yet Adopted None that are expected to have a material impact. ## Market risk As filed, 10,380 characters. The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term "market risk" refers to the risk of loss arising from adverse changes in natural gas, NGLs and oil prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market-risk exposure. All of our market-risk sensitive instruments were entered into for purposes other than trading. All accounts are U.S. dollar denominated. ### Market Risk We are exposed to market risks related to the volatility of natural gas, NGLs and oil prices as the volatility of these prices continues to impact our industry. We expect commodity prices to remain volatile and unpredictable in the future. We employ various strategies, including diverse sales locations and the use of commodity derivative instruments, to manage the risks related to these price fluctuations. These derivative instruments apply to a varying portion of our production and provide only partial price protection. These arrangements limit the benefit to us of increases in prices but offer protection in the event of price declines. Further, if our counterparties defaulted, this protection might be limited as we might not receive the benefits of the derivatives. We are at risk for changes in the fair value of all of our derivative instruments; however, such risk should be mitigated by price changes related to the underlying commodity transaction. While the use of derivative instruments could materially affect our results of operations in a particular quarter or annual period, we believe that the use of these instruments will not have a material adverse effect on our financial position or liquidity. Realized prices are primarily driven by worldwide prices for oil and spot market prices for North American natural gas production. Natural gas prices affect us more than oil prices because approximately 64% of our December 31, 2023 proved reserves were natural gas compared to 2% of proved reserves were oil. In addition, a portion of our NGLs, which are 34% of proved reserves, are also impacted by changes in oil prices. At times, we are also exposed to market risks related to changes in interest rates. These risks did not change materially from December 31, 2022 to December 31, 2023. We believe NGLs prices are somewhat seasonal, particularly for propane. Therefore, the relationship of NGLs prices to NYMEX WTI (or West Texas Intermediate) will vary due to product components, seasonality and geographic supply and demand. We sell NGLs in several regional and international markets. If we are not able to sell or store NGLs, we may be required to curtail production or shift our drilling activities to dry gas areas. The Appalachian region has limited local demand and infrastructure to accommodate ethane. We have agreements wherein we have contracted to either sell or transport ethane from our Marcellus Shale area. We cannot ensure that these facilities will remain available. If we are not able to sell ethane under at least one of our agreements, we may be required to curtail production or, as we have done in the past, purchase or divert natural gas to blend with our rich residue gas. ### Commodity Price Risk We use commodity-based derivative contracts to manage exposures to commodity price fluctuations. We do not enter into these arrangements for speculative or trading purposes. At times, certain of our derivatives are swaps where we receive a fixed price for our production and pay market prices to the counterparty. Our derivatives program may also include collars, which establish a minimum floor price and a predetermined ceiling price. Our program may also include a three-way collar which is a combination of three options: a sold call, a purchased put and a sold put. The sold call establishes the ceiling price while the purchased put establishes the floor price until the market price for the commodity falls below the sold put stock price at which price the value of the purchased put is effectively capped. We have also entered into natural gas derivative instruments containing a fixed price swap and a sold option (which we refer to as a swaption). At December 31, 2023, our derivatives program includes swaps, collars, three-way-collars and swaptions. These contracts expire monthly through December 2026. Their fair value, represented by the estimated amount that would be realized upon immediate liquidation as of December 31, 2023, approximated a net derivative asset of $424.4 million compared to a net derivative liability of $138.6 million at December 31, 2022. This change is primarily related to changes in futures prices for natural gas and oil, the settlements of derivative contracts during 2023 and the new commodity derivative contracts we entered into during 2023 for 2024, 2025 and 2026. At December 31, 2023, the following commodity derivative contracts were outstanding, excluding our basis swaps which is separately discussed below: *(in thousands)* | Period Natural Gas (a) | Contract Type | Volume Hedged | Weighted Average Hedge Price Swap | Sold Put | Floor | Ceiling | Fair Market Value | | --- | --- | --- | ---: | ---: | ---: | ---: | ---: | | 2024 | Swaps | 304,973 Mmbtu/day | $4.01 | | | | $146,481 | | 2024 | Collars | 436,694 Mmbtu/day | | | $3.50 | $5.63 | $150,456 | | 2024 | Three-way Collars | 93,511 Mmbtu/day | | $2.50 | $3.40 | $4.15 | $20,935 | | 2025 | Swaps | 400,000 Mmbtu/day | $4.12 | | | | $85,495 | | 2025 | Three-way Collars | 30,000 Mmbtu/day | | $2.70 | $4.00 | $5.00 | $4,471 | | 2026 | Swaps | 60,000 Mmbtu/day | $4.15 | | | | $6,489 | | **Crude Oil** | | | | | | | | | January-September 2024 | Swaps | 4,000 bbls/day | $80.25 | | | | $9,115 | | January-September 2024 | Collars | 832 bbls/day | | | $80.00 | $90.12 | $2,084 | (a) We sold natural gas swaptions of 40,000 Mmbtu/day for calendar year 2026 at a weighted average price of $4.11/Mmbtu that expire June 2024. The fair value of these swaptions at December 31, 2023 was a net derivative liability of $1.2 million. ### Other Commodity Risk We are impacted by basis risk as natural gas transaction prices are frequently based on industry reference prices that may vary from prices experienced in local markets. If commodity price changes in one region are not reflected in other regions, derivative commodity instruments may no longer provide the expected hedge, resulting in increased basis risk. In addition to the derivative contracts above, we have entered into natural gas basis swap agreements. The price we receive for our natural gas production can be more or less than the NYMEX price because of adjustments for delivery location ("basis"), relative quality and other factors; therefore, we have entered into basis swap agreements that effectively lock in the basis adjustments. The fair value of the natural gas basis swaps, which expire monthly through December 2026, was a net derivative asset of $18.3 million at December 31, 2023 and the volumes are for 313,453,000 Mmbtu. ### Commodity Sensitivity Analysis The following table shows the fair value of our derivative contracts and the hypothetical change in fair value that would result from a 10% and a 25% change in commodity prices at December 31, 2023. We remain at risk for possible changes in the market value of commodity derivative instruments; however, such risks should be mitigated by price changes in the underlying physical commodity (in thousands): | | | Hypothetical Change In Fair Value Increase in Commodity Price of | | Decrease in Commodity Price of | | | --- | ---: | ---: | ---: | ---: | ---: | | | Fair Value | 10% | 25% | 10% | 25% | | Swaps | $247,580 | $(91,637) | $(229,092) | $91,637 | $229,091 | | Collars | 152,540 | (32,701) | (75,366) | 35,426 | 92,944 | | Three-way collars | 25,406 | (7,245) | (18,954) | 5,817 | 11,781 | | Swaptions | (1,161) | (2,419) | (8,887) | 935 | 1,156 | | Basis swaps | 18,277 | 21,317 | 53,293 | (21,317) | (53,292) | 57 ### Counterparty Risk Our commodity-based contracts expose us to the credit risk of non-performance by the counterparty to the contracts. Our exposure is diversified among major investment grade financial institutions and commodity traders and we have master netting agreements with the majority of our counterparties that provide for offsetting payables against receivables from separate derivative contracts. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. At December 31, 2023, our derivative counterparties include fourteen financial institutions, of which all but six are secured lenders in our bank credit facility. Counterparty credit risk is considered when determining the fair value of our derivative contracts. While counterparties are major investment grade financial institutions and large commodity traders, the fair value of our derivative contracts have been adjusted to account for the risk of non-performance by certain of our counterparties, which was immaterial. ### Interest Rate Risk At December 31, 2023, we had total debt of $1.8 billion. All of our outstanding debt is based on fixed interest rates and, as a result, we do not have significant exposure to movements in market interest rates at this time. Our credit facility provides for variable interest rate borrowings; however, we did not have any borrowings outstanding as of December 31, 2023. See Note 6 to our consolidated financial statements for more information about our senior notes. The fair value of our senior debt is based on December 31, 2023 quoted market prices. The following table presents information on these fair values (in thousands): | Fixed rate debt: | Carrying Value | Fair Value | | --- | ---: | ---: | | Senior Notes due 2025 | $688,388 | $679,363 | | (The interest rate is fixed at a rate of 4.875%) | | | | Senior Notes due 2029 | 600,000 | 624,816 | | (The interest rate is fixed at a rate of 8.25%) | | | | Senior Notes due 2030 | 500,000 | 463,085 | | (The interest rate is fixed at a rate of 4.75%) | | | | | $1,788,388 | $1,767,264 | 58 ## Controls and procedures As filed, 1,875 characters. *Evaluation of Disclosure Controls and Procedures.* As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Form 10-K. Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2023 at the reasonable assurance level. *Changes in Internal Controls over Financial Reporting.* There have been no changes in our system of internal control over financial reporting during the three months ended December 31, 2023 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. *Management’s Annual Report on Internal Control over Financial Reporting.* See "Management’s Report on Internal Control over Financial Reporting" and "Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting" which appear on pages F-2 and F-3, respectively, under Item 8. Financial Statements and Supplementary Data. Filed Feb 21, 2024. Source: SEC EDGAR, the filing index for accession 0000950170-24-018046. Last ingested by Listed: Oct 30, 2026, 16:38 ET. No prices; not investment advice.