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RANGE RESOURCES CORP

RANGE RESOURCES CORPRRCEarnings & Financial Report

NYSE · Energy · Crude Petroleum & Natural Gas

Range Resources Corporation is a natural gas exploration and production company, the headquartered is in Fort Worth, Texas. It operates in the Marcellus Formation, where it is the largest land owners.

What changed in RANGE RESOURCES CORP's 10-K — 2022 vs 2023

Top changes in RANGE RESOURCES CORP's 2023 10-K

420 paragraphs added · 446 removed · 142 edited across 7 sections

Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

79 edited+20 added−11 removed121 unchanged
Increases in our level of indebtedness 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; • 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.
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.
We are also 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 below The natural gas industry is subject to extensive regulation .
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.
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 further stress on our financial flexibility.
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.
Attackers are becoming more sophisticated and both the frequency and magnitude of cyberattacks in particular are expected to increase and include, but are 34 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.
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.
We may need to 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.
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.
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. 22 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.
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.
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.
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 28 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.
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.
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 32 recognized until launched.
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 from new sources and transport the water to drilling sites, resulting in increased costs.
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.
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, Governor Wolf vetoed the disapproval resolution.
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.
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.
If any of 26 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.
If our cash flow and capital resources are insufficient to fund our debt obligations, we may be forced to sell assets, seek additional 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.
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.
In April 2022, the Pennsylvania senate failed to override 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.
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.
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 surface water or groundwater may increase costs and cause delays, interruptions or termination of our operations.
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.
Additionally, legislation could be enacted that imposes new fees or increases the 32 taxes on oil and natural gas extraction, which could result in increased operating costs and/or reduced consumer demand for our products.
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.
Such lawsuits have also alleged 30 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.
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.
Liquidity, asset quality, cost structure, product mix (natural gas, NGLs and oil) and projected commodity pricing levels are also considered by the rating agencies.
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.
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 CO 2 emissions from fossil-fuel-fired electric power plants.
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 CO 2 emissions from fossil-fuel-fired electric power plants.
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 will be diluted if additional shares are issued .
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 .
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 26 availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory and zoning approvals and other factors.
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.
Such activist efforts could result in the following: • delay or denial of drilling permits; • shortening of lease terms and reduction in lease size; • 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.
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.
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”.
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.
Anti-development activists are working to, among other things, reduce access to federal and state government lands and delay or cancel certain projects such as the development of oil and gas drilling, as well as the pipeline infrastructure needed to transport and process oil and gas production.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
While none of the species listed by FWS as threatened or endangered materially affect our operations at the present 27 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.
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.
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.
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.
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.
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 would result in material economic harm to us.
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.
Additionally, local governments in Pennsylvania are 27 authorized to adopt and implement ordinances and impose certain restrictions regarding siting of our well sites, tanks pads and other related facilities.
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.
Natural gas prices are likely to affect us more than oil prices because approximately 65% of our proved reserves were natural gas as of December 31, 2022 and at times in the past, natural gas prices have been low compared to our costs to produce.
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.
Computers and telecommunication systems 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.
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.
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. We do not engage in transactions involving crypto currency. 25 Risks related to our operations Drilling is an uncertain and costly activity .
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 .
Given uncertainties related to the use of emerging technologies, the state of markets for and the availability of verified carbon offsets, we cannot predict whether or not we will be able to timely meet our net zero GHG emissions goal.
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 are a borrower under fixed rate senior notes and maintain a bank credit facility which had a balance of $19.0 million as of December 31, 2022. 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.
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.
Cyberattacks could compromise our computer and telecommunications systems and result in disruptions to our business operations or the loss of our data and proprietary information. In addition, computers control oil and gas production, processing equipment, and distribution systems globally and are necessary to deliver our production to market.
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.
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.
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. 23 Derivative transactions may limit our potential gains and involve other risks .
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; • adverse weather conditions and changes in weather patterns; • 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 toxic gases; • 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 and explosions; • natural disasters; • 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.
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. 24 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.
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; • 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; • United States’ domestic and worldwide economic conditions; • the price and availability of, and demand for, alternative and competing forms of energy, such as nuclear, hydroelectric, wind and solar; • the effect of worldwide energy conservation efforts; • the ability of the members of OPEC and other exporting nations to mutually agree to maintain oil price and 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.
These factors include: 21 • 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 EPA has sought to achieve these reductions under the Clean Air Act and New Source Performance Standards (“NSPS”) aimed at volatile organic compounds (“VOCs”) including methane emissions from oil and natural gas sources.
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.
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.
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.
A total shut-in of production would materially 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. 28 Risks related to the industry in which we operate The natural gas industry is subject to extensive regulation .
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.
We continue to undertake actions and implement plans to strengthen our supply chain to address these pressures. Nevertheless, we expect to experience supply chain constraints and inflationary pressure on our cost structure including steel, fuel and labor, among other items, for the foreseeable future.
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.
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 now attributable to our properties located in the Appalachian Basin, all of which are located in Pennsylvania.
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.
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.
Estimates of proved reserves depend on many assumptions relating to current and future economic 29 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.
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. Security threats have subjected our operations to increased risks that could have a material adverse effect on our business.
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.
However, in third quarter 2022, our board of directors reinstated our cash dividend. 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.
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.
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.
The impact of 30 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 .
To the extent that legal challenges or any further rulemaking 29 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 .
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.
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.
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.
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. 31 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.
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.
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 indebtedness could limit our ability to successfully operate our business .
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. 22 Our debt obligations may limit our liquidity and financial flexibility .
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.
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.
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; however, we may be forced to sell assets in the event capital is not available through debt or equity markets or through additional bank debt.
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.
The market price of our common stock has been volatile. From January 1, 2020 to December 31, 2022 the price of our common stock reported by the New York Stock Exchange ranged from a low of $1.64 per share to a high of $37.44 per share.
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.
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. In January 2020, we announced that the board of directors suspended the dividend on our common stock.
However, this program may be suspended, modified or discontinued by the board of directors at any time. 31 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.
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.
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.
Disruptions or volatility in the global finance markets may lead to a contraction in credit availability impacting our ability to finance our operations. Currently, we require 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.
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.
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.
These hedging transactions can limit our potential gains if natural gas, NGLs and oil prices rise above the price established by the hedge.
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.
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.
In addition to 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.
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.
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.
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.
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.
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.
From January 1, 2023 to February 20, 2023, our common stock ranged from a low of $22.61 per share to a high of $27.01 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.
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.
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.
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.
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.
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.
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.
We can provide no assurance that our insurance coverage will adequately protect us against liability from all potential consequences, damages and losses. 25 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.
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. This final rule becomes effective 60 days after its publication in the Federal Register.
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.
In either case, the impact of the valuation allowance would be negative to our financial statements. 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.
Like many oil and gas companies, we are involved in various legal proceedings, including threatened claims, such as title, royalty, and contractual disputes.
Increased levels of drilling activity in the natural gas and oil industry could lead to increased costs of some drilling equipment, materials and supplies.
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.
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.
Certain potential legislation, such as a ban on hydraulic fracturing, could even preclude our ability to economically develop our reserves.
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. However, our ability to repurchase securities for cash is limited by our bank credit facility and certain bond indentures. 33 Dividend limitations .
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.
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 . Our management team has specifically identified and scheduled certain drilling locations for future multi-year drilling activities on our existing acreage. These drilling locations represent a significant part of our development strategy.
Our management team has specifically identified and scheduled certain drilling locations for future multi-year drilling activities on our existing acreage.
The structure of and ultimate effect of any additional tax burden cannot be estimated at this time but could be material. We may be limited in our use of net operating losses and tax credits and deductibility of business interest expense. As noted in the financial statements included with this Form 10-K, we have substantial net operating losses (“NOLs”).
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 .
As of December 31, 2022, we had a tax basis of $187.7 million related to prior year capitalized intangible drilling costs, which will be amortized over the next five years. 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.
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.
A public comment period was held on the supplemented proposed rule in January 2023, with a final rule expected later in 2023. While the extent of the final rule cannot be predicted, additional costs are likely to result from compliance with proposed provisions such as expanded monitoring requirements and more stringent emissions limits.
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.
On November 11, 2022, the EPA supplemented its proposed rule regarding NSPS to, among other things, (i) ensure that all well sites are routinely monitored for leaks, with requirements based on the type and amount of equipment on site, (ii) require the deployment of innovative and advanced monitoring technologies by establishing performance requirements that can be met by a broader array of technologies, and (iii) prevent leaks from abandoned and unplugged wells by requiring documentation that well sites are properly closed and plugged before monitoring is allowed to end.
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.
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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. 23 Throughout 2022, we experienced cost inflation due to an increase in activity within our industry, supply chain disruptions, the Russia-Ukraine conflict and global monetary policies.

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Item 3. Legal Proceedings

Legal Proceedings — active lawsuits and investigations

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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. ITEM 4. MINE SA FETY DISCLOSURES Not applicable. 36 PART II
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. ITEM 4. MINE SA FETY DISCLOSURES Not applicable. 34 PART II
While many of these matters involve inherent uncertainty, we believe that the amount of the liability, if any, ultimately incurred with respect to proceedings or claims 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.
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.
ITEM 3. LEGAL PROCEEDINGS We are the subject of, or party to, a number of pending or threatened legal actions and claims arising in the ordinary course of our business.
ITEM 3. LEGAL PROCEEDINGS 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.
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.
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. 33 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.
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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.

Item 4. Mine Safety Disclosures

Mine Safety Disclosures — required of mining issuers

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ITEM 4. Mine Safety Disclosures 36 PART II ITEM 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 37 Market for Common Stock 37 Holders of Record 37 Dividends 37 Stockholder Return Performance Presentation 38 i TABLE OF CONTENTS (continued) Page
Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 35 Market for Common Stock 35 Holders of Record 35 Dividends 35 Equity Compensation Plan Information 35 Purchases of Equity Securities by Issuer and Affiliated Purchases 35 Stockholder Return Performance Presentation 36 i TABLE OF CONTENTS (continued) Page ITEM 6. [Reserved] 36 ITEM 7.
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ITEM 4. Mine Safety Disclosures 34 PART II ITEM 5.
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Management's Discussion and Analysis of Financial Condition and Results of Operations 37 Management's Discussion and Analysis of Results of Operations 38 Management's Discussion and Analysis of Financial Condition, Cash Flows, Capital Resources and Liquidity 47 Management's Discussion of Critical Accounting Estimates 52

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

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Management’s Discussion and Analysis of Financial Condition and Results of Operations. Equity Compensation Plan Information The information required by this item is incorporated herein by reference to the 2023 Proxy Statement, which will be filed with the SEC not later than 120 days after December 31, 2022.
Management’s Discussion and Analysis of Financial Condition and Results of Operations. Equity Compensa tion Plan Information The information required by this item is incorporated herein by reference to the 2024 Proxy Statement, which will be filed with the SEC not later than 120 days after December 31, 2023.
Holders of Record Pursuant to the records of our transfer agent, as of February 20, 2023, there were approximately 873 holders of record of our common stock. Dividends The payment of dividends is subject to the formal declaration by the board of directors.
Holders of Record Pursuant to the records of our transfer agent, as of February 19, 2024, there were approximately 846 holders of record of our common stock. Dividends The payment of dividends is subject to the formal declaration by the board of directors.
ITEM 5. M ARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES Market for Common Stock Our common stock is listed on the New York Stock Exchange (“NYSE”) under the symbol “RRC”. During 2022, trading volume averaged approximately 5.0 million shares per day.
ITEM 5. M ARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES Market for Common Stock Our common stock is listed on the New York Stock Exchange ("NYSE") under the symbol "RRC". During 2023, trading volume averaged approximately 3.7 million shares per day.
The graph assumes that $100 was invested in the Company’s common stock and each index on December 31, 2017 and that dividends were reinvested. 2017 2018 2019 2020 2021 2022 Range Resources Corporation $ 100 $ 56 $ 29 $ 40 $ 107 $ 150 S&P Oil & Gas Exploration & Production Index 100 71 64 39 64 91 S&P Small Cap 600 Index 100 92 112 125 158 133 2022 Self-Constructed Peer Group (a) 100 68 75 102 184 134 (a) The 2022 Self-Constructed Peer Group includes the following twelve companies: Antero Resources Corporation, Chesapeake Energy Corporation, CNX Resources, Comstock Resources, Inc., Coterra Energy, Inc., EQT Corporation, Matador Resources, Murphy Oil, PDC Energy, SM Energy Company, Southwestern Energy Company and the S&P 500 and is weighted based on stock market capitalization. 38 ITEM 7 .
The graph assumes that $100 was invested in the Company’s common stock and each index on December 31, 2018 and that dividends were reinvested. 2018 2019 2020 2021 2022 2023 Range Resources Corporation $ 100 $ 51 $ 71 $ 189 $ 267 $ 328 S&P Oil & Gas Exploration & Production Index 100 89 55 90 128 129 S&P Small Cap 600 Index 100 123 137 173 145 168 2023 Self-Constructed Peer Group (a) 100 81 74 142 202 210 (a) The 2023 Self-Constructed Peer Group includes the following twelve companies: Antero Resources Corporation, Chesapeake Energy Corporation, CNX Resources, Comstock Resources, Inc., Coterra Energy, Inc., EQT Corporation, Matador Resources, Murphy Oil, PDC Energy (included through August 2023 when it was acquired by Chevron Corp.), SM Energy Company, Southwestern Energy Company and the S&P 500 index and is weighted based on stock market capitalization.
The graph compares the change in the cumulative total return of Range’s common stock, the S&P Oil and Gas Exploration and Production Index, and the S&P Small Cap 600 Index.
The graph compares the change in the cumulative total return of Range’s common stock, the S&P Oil and Gas Exploration and Production Index, the S&P Small Cap 600 Index and a customized peer group which matches the peer group selected by our compensation committee of the board of directors which is used in our performance unit program.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers Purchases of our common stock are as follows: Three Months Ended December 31, 2022 Period Total Number of Shares Purchased Average Price Paid Per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs Approximate Dollar Amount of Shares that May Yet Be Purchased Under Plans or Programs (a) October 2022 540,000 $ 27.72 540,000 $ 1,171,161,132 November 2022 1,040,000 $ 27.58 1,040,000 $ 1,142,476,809 December 2022 1,610,000 $ 26.13 1,610,000 $ 1,100,400,840 3,190,000 3,190,000 (a) In October 2019, our board of directors authorized a $100 million common stock repurchase program.
Purchases of our common stock in fourth quarter 2023 were as follows: Three Months Ended December 31, 2023 Period Total Number of Shares Purchased Average Price Paid Per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs Approximate Dollar Amount of Shares that May Yet Be Purchased Under Plans or Programs October 2023 50,000 $ 29.84 50,000 $ 1,089,244,444 November 2023 — $ — — $ 1,089,244,444 December 2023 265,000 $ 29.74 265,000 $ 1,081,359,316 315,000 315,000 35 Stockhol der Return Performance Presentation The following graph is included in accordance with the SEC’s executive compensation disclosure rules.
In February 2022, our board of directors subsequently increased the authorization under the program for a cumulative approval of $530.0 million. In October 2022, the board of directors authorized an additional repurchase of up to $1.0 billion of outstanding common stock under the program, which includes fees, commissions and expenses.
Purchases of Equity S e curities by the Issuer and Affiliated Purchasers In 2019, our board of directors authorized a $100 million common stock repurchase program. In 2022, our board of directors increased the authorization under the program.
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As of December 31, 2022, these repurchased shares are held as treasury stock. 37 Stockhol der Return Performance Presentation The following graph is included in accordance with the SEC’s executive compensation disclosure rules. This historic stock price performance is not necessarily indicative of future stock performance.
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As of December 31, 2023, these repurchased shares are held as treasury stock and we have approximately $1.1 billion of remaining authorization under the program.
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We have added a self-constructed Peer Group that matches the peer group selected by our Compensation Committee of the board of directors and is used in our performance unit program along with deleting three indexes which include the S&P Mid Cap 400 Index, the Dow Jones U.S. Exploration & Production Index and the ISE Revere National Gas Index.
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This historic stock price performance is not necessarily indicative of future stock performance.
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We believe these changes more accurately provide a broader comparison of stock performance along with using indexes that are most commonly used in our industry or indexes in which we are included.
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MANAGEMENT’S DISCUSSIO N AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF 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.
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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, 2022 and 2021.
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For similar discussions of the year ended December 31, 2021 compared to December 31, 2020 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, 2021, which was filed with the SEC on February 22, 2022.
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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.
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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.
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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.
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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.
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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; • continuing to optimize drilling, completion and operational efficiencies; • remaining focused on maintaining a competitive cost structure; • continuing to manage price risk through the hedging of our production; and • continuing to manage our balance sheet.
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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 capital expenditures; and • our ability to borrow and raise additional capital.
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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.
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Our corporate headquarters is located in Fort Worth, Texas. 39 Key 2022 highlights include: Enhanced the balance sheet, increased return of capital to investors and preserved liquidity • In first quarter 2022, we issued an aggregate principal amount of $500.0 million in new 4.75% senior notes due 2030 and used the proceeds to redeem $850.0 million of our 9.25% senior notes due 2026 at a premium.
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In addition, in mid-December 2022, we redeemed the remaining 5.0% senior notes due 2023 at par. As of December 31, 2022, we had $19.0 million borrowed under our bank credit facility, $207,000 of cash on hand and $1.2 billion available under our bank credit facility.
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The table below details the changes in our outstanding debt principal balances from December 31, 2021 to December 31, 2022 (in thousands): December 31, 2021 Change December 31, 2022 Bank debt $ — $ 19,000 $ 19,000 Senior notes 4.75% senior notes due 2030 — 500,000 500,000 5.00% senior notes due 2022 169,589 (169,589 ) — 5.875% senior notes due 2022 48,528 (48,528 ) — 5.00% senior notes due 2023 532,335 (532,335 ) — 4.875% senior notes due 2025 750,000 — 750,000 9.25% senior notes due 2026 850,000 (850,000 ) — 8.25% senior notes due 2029 600,000 — 600,000 Total senior notes 2,950,452 (1,100,452 ) 1,850,000 Total debt 2,950,452 (1,081,452 ) 1,869,000 Cash balance (as disclosed on balance sheet) (214,422 ) 214,215 (207 ) Total debt, net of cash $ 2,736,030 $ (867,237 ) $ 1,868,793 • Our banks’ committed borrowing capacity remained at $1.5 billion after completing our semi-annual borrowing base redetermination in September 2022. • Our next significant long-term debt maturity is $750.0 million due in 2025. • Increased return of capital to investors by: o Repurchasing $399.7 million of our common stock (14.0 million shares) in 2022 via the share repurchase program; and o Distributing dividends totaling $38.6 million.
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Improved financial and operational results • Significant increases in realized prices resulted in: o An increase of $1.7 billion of natural gas, NGLs and oil revenues when compared to 2021; and o An additional loss on commodity derivatives settled of $670.0 million when compared to 2021. • Our diluted net income per share was $4.69 in 2022 compared to $1.61 in 2021. • Cash provided by operating activities was $1.9 billion, an increase of $1.1 billion when compared to 2021. • Delivered strong operational execution along with focusing on cost control and managing cost inflation while emphasizing safety and protection of the environment. • Increased proved reserves to 18.1 Tcfe, 2% higher than 2021.
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Continued to focus on safe, responsible and sustainable operations • Continued to recycle approximately 100% of produced water. • Increased leak detection inspections to eight times a year. • Pilot tested the use of compressed air pneumatic controllers. • Achieved a 50% reduction in number of workforce recordable injuries with a Total Recordable Incident Rate of 0.46. • Achieved a 50% reduction in number of workforce days away restricted treatment injuries with a DART of 0.11. 40 Management’s Discussion and Analysis of Results of Operations Commodity prices have remained volatile.
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Benchmarks for natural gas, oil and NGLs increased in 2022 compared to 2021 and, as a result, we experienced significant increases in our price realizations when compared to the same period of 2021.
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We had many operational, financial and strategic successes in 2022 as we continued to focus on enhancing margins and returns, driving operational efficiencies and returning capital to stockholders. We believe we have positioned ourselves for long-term success through the commodity price cycles.
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Overview of 2022 Results For the year ended December 31, 2022, we experienced an increase in revenue from the sale of natural gas, NGLs and oil due to a 65% increase in net realized prices (average prices including all derivative settlements and third-party transportation costs paid by us) when compared to 2021.
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Daily production in 2022 averaged 2.12 Bcfe compared to 2.13 Bcfe in 2021. Average natural gas differentials were below NYMEX and slightly lower than the prior year. During 2022, we recognized net income of $1.2 billion, or $4.69 per diluted common share compared to $411.8 million, or $1.61 per diluted common share during 2021.
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The improvement in net income for the year ended December 31, 2022 when compared to 2021 is due to significantly higher realized prices.
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During 2022, our financial and operating performance included the following results: • reduced total debt $1.1 billion and issued $500.0 million of new 4.75% senior notes which were used to refinance a portion of our 8.25% senior notes; • increased cash flow from operating activities by 135% from the same period of 2021; • drilled 59 net wells with a 100% success rate; • continued development of our Marcellus Shale inventory by maintaining production, proving up acreage and acquiring additional unproved acreage; • increased revenue from the sale of natural gas, NGLs and oil by 53% from the same period of 2021 with a 53% increase in average realized prices (before cash settlements on our derivatives); • increased revenue from the sale of natural gas, NGLs and oil (including settlements on our derivatives) by 39% from the same period of 2021; • increased direct operating expense per mcfe 10%, or 0.01 per mcfe from 2021; • held general and administrative expenses per mcfe flat when compared to 2021; • reduced our DD&A rate per mcfe 2% from 2021; • entered into additional commodity-based derivative contracts for 2023 through 2026; and • ended the year with cash on hand of $207,000 and stockholders’ equity of $2.9 billion.
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We generated $1.9 billion of cash flow from operating activities in 2022, an increase of $1.1 billion from 2021 which reflects significantly higher realized prices and lower comparative working capital outflows ($169.3 million outflow during 2022 compared to $241.7 million outflow in 2021). We ended 2022 with $1.2 billion of available committed borrowing capacity.
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Acquisitions During 2022, we invested $28.7 million to acquire unproved acreage compared to $22.0 million in 2021. We continue selective acreage leasing and lease renewals to consolidate our acreage positions in the Marcellus Shale play in Pennsylvania. 2023 Outlook As we enter 2023, we believe we are positioned for sustainable long-term success.
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For 2023, we expect our capital budget to be in the range of $570.0 million to $615.0 million for natural gas, NGLs, crude oil and condensate related activities, excluding proved property acquisitions, for which we do not budget.
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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 2023 capital budget to achieve production similar to our 2022 production.
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Our 2023 capital budget is designed to focus on continuing to improve corporate returns and generating free cash flow and 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.
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The price risk on a portion of our forecasted natural gas, NGLs and oil production for 2023 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 41 during 2023.
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We also expect inflationary pressures, which ultimately depend on various factors beyond our control, to continue during 2023. We continue to assess and monitor the impact and consequences of this on our operations. Market Conditions Prices for natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows.
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Natural gas, NGLs and oil benchmarks increased in 2022 when compared to the same period of 2021 and, as a result, we experienced a significant increase in price realizations.
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As we continue to monitor the impact of the actions of OPEC and other large producing nations, the Russia-Ukraine conflict, global inventories of oil and gas and the uncertainty associated with potential recession on oil demand, future monetary policy and governmental policies aimed at transitioning towards lower carbon energy, we expect prices for some or all of the commodities we produce to remain volatile.
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Futures prices have declined based on the relatively mild winter and infrastructure constraints. Longer term natural gas futures prices remain strong 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.
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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.
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Other factors such as the pace and extent of tightening global monetary policy and the effectiveness of responses to combat the COVID-19 virus may impact the recovery of world economic growth and the demand for oil, natural gas and NGLs.
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In addition, in response to continued supply chain disruptions attributable to the virus, the Russia-Ukraine conflict and global monetary policies over the last few years, cost inflation is occurring. We continue to assess and monitor the impact and consequences of these factors on our operations.
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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.
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Recently, natural gas prices have decreased, when compared to December 2022, with the average NYMEX monthly settlement price for natural gas decreasing to $3.11 per mcf for February 2023 with the recent mild winter weather. Crude oil prices have increased, when compared to December 2022, to $78.16 per barrel in January 2023.
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The following table lists related benchmarks for natural gas, oil and NGLs composite prices for the years ended December 31, 2022 and 2021.
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Year Ended December 31, 2022 2021 Benchmarks: Average NYMEX prices (a) Natural gas (per mcf) $ 6.64 $ 3.88 Oil (per bbl) $ 94.90 $ 67.93 Mont Belvieu NGLs composite (per gallon) (b) $ 0.90 $ 0.74 (a) Based on average of monthly last day settlement prices on the New York Mercantile Exchange (“NYMEX”).
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(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.
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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 2022, natural gas, NGLs and oil sales increased 53% from 2021 with a 53% increase in realized prices (excluding cash settlements on our derivatives).
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The following table illustrates the primary components of natural gas, NGLs, crude oil and condensate sales for the last two years (in thousands): Year Ended December 31, 2022 2021 Change % Change Natural gas, NGLs and Oil sales Natural gas $ 3,364,111 $ 1,896,231 $ 1,467,880 77 % NGLs 1,308,574 1,135,826 172,748 15 % Oil and condensate 238,407 182,970 55,437 30 % Total natural gas, NGLs and oil sales $ 4,911,092 $ 3,215,027 $ 1,696,065 53 % 42 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.
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Our production for the last two years is set forth in the following table: Year Ended December 31, 2022 2021 Change % Change Production (a) Natural gas (mcf) 539,442,624 541,021,442 (1,578,818 ) — % NGLs (bbls) 36,392,033 36,372,862 19,171 — % Crude oil and condensate (bbls) 2,715,681 3,044,026 (328,345 ) (11 %) Total (mcfe) (b) 774,088,908 777,522,772 (3,433,864 ) — % Average daily production (a) Natural gas (mcf) 1,477,925 1,482,251 (4,326 ) — % NGLs (bbls) 99,704 99,652 52 — % Crude oil and condensate (bbls) 7,440 8,340 (900 ) (11 %) Total (mcfe) (b) 2,120,792 2,130,199 (9,407 ) — % (a) Represents volumes sold regardless of when produced.
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(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.
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Our average realized price (including all derivative settlements and third-party transportation costs paid by Range) received during 2022 was $3.17 per mcfe compared to $1.92 per mcfe in 2021. 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.
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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.
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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 operations. Average sales prices (excluding derivative settlements) do include transportation costs where we receive net proceeds from the purchaser.
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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.
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Average realized price calculations for the last two years are shown below: Year Ended December 31, 2022 2021 Change % Change Average Prices Average sales prices (excluding derivative settlements): Natural gas (per mcf) $ 6.24 $ 3.50 $ 2.74 78 % NGLs (per bbl) 35.96 31.23 4.73 15 % Crude oil (per bbl) 87.79 60.11 27.68 46 % Total (per mcfe) (a) 6.34 4.13 2.21 53 % Average realized prices (including all derivative settlements): Natural gas (per mcf) $ 4.16 $ 2.74 $ 1.42 52 % NGLs (per bbl) 35.62 28.70 6.92 24 % Crude oil (per bbl) 57.39 46.16 11.23 24 % Total (per mcfe) (a) 4.78 3.43 1.35 39 % Average realized prices (including all derivative settlements and third-party transportation costs paid by Range): Natural gas (per mcf) $ 2.90 $ 1.51 $ 1.39 92 % NGLs (per bbl) 20.08 14.64 5.44 37 % Crude oil (per bbl) 57.39 45.86 11.53 25 % Total (per mcfe) (a) 3.17 1.92 1.25 65 % (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. 43 Realized prices include the impact of basis differentials and gains or losses realized from our basis hedging.
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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.
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The following table provides this impact on a per mcf basis: Year Ended December 31, 2022 2021 Average natural gas differentials below NYMEX $ (0.40 ) $ (0.38 ) Realized gains on basis hedging $ 0.11 $ 0.04 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): Year Ended December 31, 2021 Price Variance Volume Variance 2022 Natural gas Price (per mcf) $ 3.50 $ 2.74 $ — $ 6.24 Production (Mmcf) 541,021 — (1,578 ) 539,443 Natural gas sales $ 1,896,231 $ 1,473,414 $ (5,534 ) $ 3,364,111 Year Ended December 31, 2021 Price Variance Volume Variance 2022 NGLs Price (per bbl) $ 31.23 $ 4.73 $ — $ 35.96 Production (Mbbls) 36,373 — 19 36,392 NGLs sales $ 1,135,826 $ 172,150 $ 598 $ 1,308,574 Year Ended December 31, 2021 Price Variance Volume Variance 2022 Crude oil Price (per bbl) $ 60.11 $ 27.68 $ — $ 87.79 Production (Mbbls) 3,044 — (328 ) 2,716 Crude oil sales $ 182,970 $ 75,173 $ (19,736 ) $ 238,407 Year Ended December 31, 2021 Price Variance Volume Variance 2022 Consolidated Price (per mcfe) $ 4.13 $ 2.21 $ — $ 6.34 Production (Mmcfe) 777,523 — (3,434 ) 774,089 Total natural gas, NGLs and oil sales $ 3,215,027 $ 1,710,264 $ (14,199 ) $ 4,911,092 44 Transportation, gathering, processing and compression expense was $1.2 billion in 2022 and in 2021.
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These third-party costs are slightly higher due to the impact of higher NGLs prices which result in higher processing costs, higher fuel costs and higher electricity costs partially offset by the expiration of certain demand charges in our northeast Pennsylvania properties.
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We have included these costs in the calculation of average realized prices (including all derivative settlements and third-party transportation expenses paid by Range).
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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: Year Ended December 31, 2022 2021 Change % Change Natural gas $ 677,316 $ 661,990 $ 15,326 2 % NGLs 565,614 511,568 54,046 11 % Oil 11 911 (900 ) (99 %) Total $ 1,242,941 $ 1,174,469 $ 68,472 6 % Natural gas (per mcf) $ 1.26 $ 1.22 $ 0.04 3 % NGLs (per bbl) $ 15.54 $ 14.06 $ 1.48 11 % Oil (per bbl) $ — $ 0.30 $ (0.30 ) (100 %) Derivative fair value (loss) income was a loss of $1.2 billion in 2022 compared to a loss of $650.2 million in 2021.
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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.
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Gains on our derivatives generally indicate lower wellhead revenues in the future while losses indicate higher future wellhead revenues. At December 31, 2022, our commodity derivative contracts were recorded at their fair value, which was a net derivative liability of $138.6 million, a decrease of $30.9 million from the $169.5 million net derivative liability recorded as of December 31, 2021.
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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 $521,000 as of December 31, 2022 compared to a net derivative asset of $16.0 million as of December 31, 2021.
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The following table summarizes the impact of our commodity derivatives for the last two years (in thousands): Year Ended December 31, 2022 2021 Derivative fair value loss per consolidated statements of operations $ (1,188,506 ) $ (650,216 ) Non-cash fair value (loss) gain: (1) Natural gas derivatives $ (2,392 ) $ (130,114 ) Oil derivatives 14,783 (23,879 ) NGLs derivatives 2,931 14,100 Freight derivatives (114 ) (990 ) Contingent consideration (13,560 ) 10,680 Total non-cash fair value gain (loss) (1) $ 1,648 $ (130,203 ) Net cash (payment) receipt on derivative settlements: Natural gas derivatives $ (1,119,940 ) $ (415,228 ) Oil derivatives (82,546 ) (42,447 ) NGLs derivatives (12,168 ) (91,838 ) Contingent consideration 24,500 29,500 Total net cash payment $ (1,190,154 ) $ (520,013 ) (1) Non-cash fair value adjustments on commodity derivatives is a non-GAAP measure.
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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.
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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.
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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 operations. 45 Brokered natural gas, marketing and other revenue was $424.2 million in 2022 compared to $365.4 million in 2021.
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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.
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The 2022 period includes $408.6 million of revenue from the sale of natural gas that is not related to our production (brokered) and $2.8 million of revenue from the sale of NGLs that is not related to our production.
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The 2021 period includes $342.4 million of revenue from the brokered sale of natural gas and $6.9 million of revenue from the sale of NGLs that is not related to our production. These revenues increased compared to 2021 due to higher sales prices partially offset by lower brokered volumes.
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The twelve months ended December 31, 2021 also includes $8.8 million received as part of a capacity release agreement. Costs and Expenses per mcfe We believe some of our expense fluctuations are best analyzed on a unit-of-production, or per mcfe, basis.
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The following presents information about certain of our expenses on a per mcfe basis for the last two years: Year Ended December 31, 2022 2021 Change % Change Direct operating expense $ 0.11 $ 0.10 $ 0.01 10 % Taxes other than income expense 0.05 0.04 0.01 25 % General and administrative expense 0.22 0.22 — — % Interest expense 0.21 0.29 (0.08 ) (28 %) Depletion, depreciation and amortization expense 0.46 0.47 (0.01 ) (2 %) Direct operating expense was $84.3 million in 2022 compared to $75.3 million in 2021.
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Direct operating expenses include normally recurring expenses to operate and produce our wells, non-recurring workovers and repair-related expenses. On an absolute basis, our direct operating expenses for 2022 increased 12% from the prior year primarily due to higher water hauling/handling costs and higher contract labor costs.
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We incurred $3.0 million of workover costs in 2022 compared to $3.4 million of workover costs in 2021. On a per mcfe basis, operating expense for 2022 increased $0.01, or 10% from the same period of 2021, with the increase due to higher water hauling/handling costs.
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Stock-based compensation expense represents the amortization of equity grants as part of the compensation of field employees.

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Item 6. [Reserved]

Selected Financial Data — reserved (removed by SEC in 2021)

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ITEM 6. [Reserved] ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 39 Overview of Our Business 39 Management's Discussion and Analysis of Results of Operations 41 Management's Discussion and Analysis of Financial Condition, Cash Flows, Capital Resources and Liquidity 50 Management's Discussion of Critical Accounting Estimates 55
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ITEM 6. RE SERVED 36 ITEM 7 . MANAGEMENT’S DISCUSSIO N AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF 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.
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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.
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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.
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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.
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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.
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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.
Added
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.
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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.
Added
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.
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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.
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Our corporate headquarters is located in Fort Worth, Texas.
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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. 37 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.
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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.
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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.
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The decrease in net income for the year ended December 31, 2023 when compared to 2022 is primarily due to significantly lower realized prices.
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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.
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Daily production in 2023 averaged 2.14 Bcfe compared to 2.12 Bcfe in 2022.
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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.
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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. 38 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.
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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.
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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.
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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.
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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.
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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.
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Market Conditions We believe we are positioned for sustainable long-term success.
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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.
Added
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.
Added
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.
Added
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.
Added
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.
Added
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.
Added
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.
Added
The following table lists related benchmarks for natural gas, oil and NGLs composite prices for the years ended December 31, 2023 and 2022.
Added
Year Ended December 31, 2023 2022 Benchmarks: Average NYMEX prices (a) 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").
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(b) Based on our estimated NGLs product composition per barrel.
Added
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. 39 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.
Added
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.
Added
The following table illustrates the primary components of natural gas, NGLs, crude oil and condensate sales for the last two years (in thousands): Year Ended December 31, 2023 2022 Change % Change Natural gas, NGLs and Oil sales 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.
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Our production for the last two years is set forth in the following table: Year Ended December 31, 2023 2022 Change % Change Production (a) 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.
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(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.
Added
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.
Added
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.
Added
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.
Added
Average realized price calculations for the last two years are shown below: Year Ended December 31, 2023 2022 Change % Change Average Prices Average sales prices (excluding derivative settlements): 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.
Added
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.
Added
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): Year Ended December 31, 2022 Price Variance Volume Variance 2023 Natural gas 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 Year Ended December 31, 2022 Price Variance Volume Variance 2023 NGLs 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 Year Ended December 31, 2022 Price Variance Volume Variance 2023 Crude oil 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 Year Ended December 31, 2022 Price Variance Volume Variance 2023 Consolidated 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.
Added
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).
Added
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: Year Ended December 31, 2023 2022 Change % Change Transportation, gathering, processing and compression 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.
Added
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.
Added
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.
Added
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.
Added
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.
Added
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.
Added
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.
Added
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.
Added
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.
Added
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.
Added
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.
Added
Costs and Expenses per mcfe We believe some of our expense fluctuations are best analyzed on a unit-of-production, or per mcfe, basis.
Added
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.
Added
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.
Added
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.
Added
Stock-based compensation expense represents the amortization of equity grants as part of the compensation of field employees.
Added
The following table summarizes direct operating expenses per mcfe for the last two years: Year Ended December 31, 2023 2022 Change % Change Direct operating 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.
Added
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.
Added
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.
Added
The following table summarizes taxes other than income per mcfe for the last two years: Year Ended December 31, 2023 2022 Change % Change Taxes other than income 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.
Added
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.
Added
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.
Added
The following table summarizes general and administrative expenses per mcfe for the last two years: Year Ended December 31, 2023 2022 Change % Change General and administrative 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.
Added
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.
Added
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.
Added
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.
Added
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.
Added
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.
Added
The following table summarizes DD&A expenses per mcfe for the last two years: Year Ended December 31, 2023 2022 Change % Change DD&A 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.
Added
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.
Added
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. 45 Brokered natural gas and marketing expense was $202.9 million in 2023 compared to $427.0 million in 2022.
Added
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.

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Item 7. Management's Discussion & Analysis

Management's Discussion & Analysis (MD&A) — revenue / margin commentary

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Additionally, while the Federal Bureau of Land Management released a final rule setting forth disclosure requirements and other regulatory mandates for hydraulic fracturing on federal lands in March 2015, on December 29, 2017, the United States Department of Interior rescinded the 2015 rule that would have set new environmental limitations on hydraulic fracturing, or fracking, on public lands because it believed the 2015 rule imposed administrative burdens and compliance costs that were not justified.
Additionally, while the Federal Bureau of Land Management released a final rule setting forth disclosure requirements and other regulatory mandates for hydraulic fracturing on federal lands in March 2015, on December 29, 2017, the United States Department of the Interior rescinded the 2015 rule that would have set new environmental limitations on hydraulic fracturing, or fracking, on public lands because it believed the 2015 rule imposed administrative burdens and compliance costs that were not justified.
However, on January 20, 2021, President Biden signed an executive order directing the United States to rejoin the Paris Agreement, which 19 became official on February 19, 2021. It is not yet clear how rejoining the Paris Agreement or any separately negotiated agreement could impact us.
However, on January 20, 2021, President Biden signed an executive order directing the United States to rejoin the Paris Agreement, which became official on February 19, 2021. It is not yet clear how rejoining the Paris Agreement or any separately negotiated agreement could impact us.
Since such legislative review period would have extended past the December 16, 2022 deadline for Pennsylvania to submit to the EPA a plan implementing the regulation of VOC emissions from oil and gas sources, the PEQB, on November 30, 2022, adopted the rule for conventional oil and gas sources as an emergency certified final-omitted rulemaking and former Governor Tom Wolf certified that promulgation of such is necessary to respond to an emergency circumstance.
Since this legislative review period would have extended past the December 16, 2022 deadline for Pennsylvania to submit to the EPA a plan implementing the regulation of VOC emissions from oil and gas sources, the PEQB, on November 30, 2022, adopted the rule for conventional oil and gas sources as an emergency certified final-omitted rulemaking and former Governor Tom Wolf certified that promulgation of such is necessary to respond to an emergency circumstance.
We have entered into several ethane agreements to sell or transport ethane from our Marcellus Shale area. For more information, see Item 1A. Risk Factors – Our business depends on natural gas and oil transportation and NGLs processing facilities, most of which are owned by others and we rely on our ability to contract with those parties.
We have entered into several ethane agreements to sell or transport ethane from our Marcellus Shale area. For more information, see Item 1A. Risk Factors – Our business depends on natural gas and oil transportation and NGLs processing facilities, most of which are owned by others and depends on our ability to contract with those parties.
For instance, on February 25, 2021, the Delaware River Basin Commission, which supplies drinking water for more than 13 million people in Pennsylvania, Delaware, New Jersey, and New York, approved a final rule prohibiting high volume hydraulic fracturing in the Delaware River Basin, which includes a portion of the Marcellus Shale that overlaps the Delaware watershed, specifically in northeastern Pennsylvania and southern New York State.
For instance, on February 25, 2021, the Delaware River Basin Commission, which supplies drinking water for more than 13 million people in Pennsylvania, Delaware, New Jersey, and New York, approved a final rule prohibiting high volume 16 hydraulic fracturing in the Delaware River Basin, which includes a portion of the Marcellus Shale that overlaps the Delaware watershed, specifically in northeastern Pennsylvania and southern New York State.
Nevertheless, any future changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses. We currently own or lease, and have in the past owned or leased, properties that have been used for many years for the exploration and production of crude oil and natural gas.
Nevertheless, any future changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses. 15 We currently own or lease, and have in the past owned or leased, properties that have been used for many years for the exploration and production of crude oil and natural gas.
Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned. Henry Hub price . A natural gas benchmark price quoted at settlement date average. mbbl. One thousand barrels of crude oil or other liquid hydrocarbons. mcf. One thousand cubic feet of gas. mcf per day.
The total acres or wells, as the case may be, in which a working interest is owned. Henry Hub price . A natural gas benchmark price quoted at settlement date average. mbbl. One thousand barrels of crude oil or other liquid hydrocarbons. mcf. One thousand cubic feet of gas. mcf per day.
The proposed rule was reviewed by the Pennsylvania Office of the Attorney General followed by a sixty day public comment period. Thereafter, the Pennsylvania Environmental Quality Board (the “PEQB”) adopted the proposed rulemaking and an additional public comment period on July 27, 2020. On May 4, 2022, the PEQB withdrew the rule.
The proposed rule was reviewed by the Pennsylvania Office of the Attorney General followed by a sixty day public comment period. Thereafter, the Pennsylvania Environmental Quality Board (the "PEQB") adopted the proposed rulemaking and an additional public comment period on July 27, 2020. On May 4, 2022, the PEQB withdrew the rule.
On an international level, the United States was one of almost 200 nations that, in December 2015, agreed to an international climate change agreement in Paris, France the (“Paris Agreement”) that calls for countries to set their own GHG emissions targets and be transparent about the measures each country will use to achieve its GHG emissions targets, which agreement formally entered into force on November 4, 2016.
On an international level, the United States was one of almost 200 nations that, in December 2015, agreed to an international climate change agreement in Paris, France the ("Paris Agreement") that calls for countries to set their own GHG emissions targets and be transparent about the measures each country will use to achieve its GHG emissions targets, which agreement formally entered into force on November 4, 2016.
Moreover, from time to time, Congress has considered adopting legislation intended to provide for federal regulation of hydraulic fracturing and to require disclosure of the 17 chemicals used in the hydraulic fracturing process.
Moreover, from time to time, Congress has considered adopting legislation intended to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process.
Proved reserves. The quantities of crude oil, natural gas and NGLs that geological and engineering data can estimate with reasonable certainty to be economically producible within a reasonable time from known reservoirs under existing economic, operating and regulatory conditions prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.
The quantities of crude oil, natural gas and NGLs that geological and engineering data can estimate with reasonable certainty to be economically producible within a reasonable time from known reservoirs under existing economic, operating and regulatory conditions prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.
However, current regulatory requirements may change, currently unforeseen environmental incidents may occur, or past non-compliance with environmental laws or regulations may be discovered. See Item 1A. Risk Factors – The natural gas industry is subject to extensive regulation . We do not believe we are affected differently by these regulations than others in the industry. 13 General Overview.
However, current regulatory requirements may change, currently unforeseen environmental incidents may occur, or past non-compliance with environmental laws or regulations may 12 be discovered. See Item 1A. Risk Factors – The natural gas industry is subject to extensive regulation . We do not believe we are affected differently by these regulations than others in the industry. General Overview.
New state and federal regulatory initiatives that could have a significant adverse impact on us may periodically be proposed and enacted. Waste handling. We also may incur liability under the Resource Conservation and Recovery Act, as amended (“RCRA”) and comparable state laws, which impose requirements related to the handling and disposal of non-hazardous solid wastes and hazardous wastes.
New state and federal regulatory initiatives that could have a significant adverse impact on us may periodically be proposed and enacted. Waste handling. We also may incur liability under the Resource Conservation and Recovery Act, as amended ("RCRA") and comparable state laws, which impose requirements related to the handling and disposal of non-hazardous solid wastes and hazardous wastes.
Proved reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a 21 new well and (ii) through installed extracting equipment and infrastructure operational at the time of the reserve estimate if the extraction is by means not involving a well.
Proved reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well and (ii) through installed extracting equipment and infrastructure operational at the time of the reserve estimate if the extraction is by means not involving a well. 20 Proved reserves.
Intrastate liquids pipeline transportation rates, terms and conditions are subject to regulation by numerous federal, state and local authorities and, in a number of instances, the ability to transport and sell such products on interstate pipelines is dependent on pipelines that are also subject to FERC jurisdiction under the Interstate Commerce Act (the “ICA”).
Intrastate liquids pipeline transportation rates, terms and conditions are subject to regulation by numerous federal, state and local authorities and, in a number of instances, the ability to transport and sell such products on interstate pipelines is dependent on pipelines that are also subject to FERC jurisdiction under the Interstate Commerce Act (the "ICA").
We believe that our operations are in substantial compliance with the OSHA requirements. 20 GLOSSARY OF CERTA IN DEFINED TERMS The terms defined in this glossary are used in this report. bbl. One stock tank barrel, or 42 U.S. gallons liquid volumes, used herein in reference to crude oil or other liquid hydrocarbons. bcf .
We believe that our operations are in substantial compliance with the OSHA requirements. 19 GLOSSARY OF CERTA IN DEFINED TERMS The terms defined in this glossary are used in this report. bbl. One stock tank barrel, or 42 U.S. gallons liquid volumes, used herein in reference to crude oil or other liquid hydrocarbons. bcf .
Based on these findings, the EPA adopted regulations under the existing Clean Air Act establishing Title V and Prevention of Significant Deterioration (“PSD”) permitting reviews for GHG emissions from certain large stationary sources that already are potential major sources of certain principal, or criteria, pollutant emissions.
Based on these findings, the EPA adopted regulations under the existing Clean Air Act establishing Title V and Prevention of Significant Deterioration ("PSD") permitting reviews for GHG emissions from certain large stationary sources that already are potential major sources of certain principal, or criteria, pollutant emissions.
We did not have any material capital or other non-recurring expenditures in connection with complying with environmental laws or environmental remediation matters in 2022, nor do we anticipate that such expenditures will be material in 2023. However, we regularly incur expenditures and undertake projects to comply with environmental laws and to optimize our emissions performance.
We did not have any material capital or other non-recurring expenditures in connection with complying with environmental laws or environmental remediation matters in 2023, nor do we anticipate that such expenditures will be material in 2024. However, we regularly incur expenditures and undertake projects to comply with environmental laws and to optimize our emissions performance.
These expenses vary and are primarily based on volume, distance shipped and the fee charged by the third-party gatherers and transporters. We also have contracts based on percent of proceeds. Transportation 12 capacity on these gathering and transportation systems and pipelines is occasionally constrained.
These expenses vary and are primarily based on volume, distance shipped and the fee charged by the third-party gatherers and transporters. We also have processing contracts based on percent of proceeds. Transportation capacity on these gathering and transportation systems and pipelines is occasionally constrained.
In 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present a danger to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic conditions.
In 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases ("GHGs") present a danger to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic conditions.
Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of greater than threshold quantities of oil.
Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as SPCC plans, in connection with on-site storage of greater than threshold quantities of oil.
The Federal Water Pollution Control Act, as amended (the “CWA”), and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas wastes, into federal and state waters.
The Federal Water Pollution Control Act, as amended (the "CWA"), and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas wastes, into federal and state waters.
Furthermore, on January 27, 2021, President Biden issued executive orders for the purpose of combatting climate change including pausing new oil and gas leases on federal land and cutting fossil fuel subsidies.
Furthermore, on January 27, 2021, President Biden issued executive orders for the purpose of combating climate change including pausing new oil and gas leases on federal land and cutting fossil fuel subsidies.
The ICA requires, among other things, that rates and terms and conditions of service on interstate common carrier pipelines be “just and reasonable.” Such pipelines must also provide jurisdictional service in a manner that is not unduly discriminatory or unduly preferential. Shippers have the power to challenge new and existing rates and terms and conditions of service before the FERC.
The ICA requires, among other things, that rates and terms and conditions of service on interstate common carrier pipelines be just and reasonable. Such pipelines must also provide jurisdictional service in a manner that is not unduly discriminatory or unduly preferential. Shippers have the power to challenge new and existing rates and terms and conditions of service before the FERC.
Drilling fluids, produced waters, and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy are currently regulated by the United States Environmental Protection Agency (“EPA”) and state agencies under RCRA’s less stringent non-hazardous solid waste 16 provisions.
Drilling fluids, produced waters, and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy are currently regulated by the United States Environmental Protection Agency ("EPA") and state agencies under RCRA’s less stringent non-hazardous solid waste provisions.
More recently, in December 2022, the Delaware River Basin Commission voted to prohibit wastewater from hydraulic fracturing operations from being deposited into the Delaware River Basins waters or land.
More recently, in December 2022, the Delaware River Basin Commission voted to prohibit wastewater from hydraulic fracturing operations from being deposited into the Delaware River Basin's waters or land.
The FERCs regulations include a methodology for oil pipelines to change their rates through the use of an index system that establishes ceiling levels for such rates.
The FERC's regulations include a methodology for oil pipelines to change their rates through the use of an index system that establishes ceiling levels for such rates.
The anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities or otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to the FERC’s jurisdiction which includes the reporting requirements under Order 704 (as defined and described below).
The anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities or otherwise non-jurisdictional entities to the extent the activities are conducted in connection with gas sales, purchases or transportation subject to the FERC’s jurisdiction which includes the reporting requirements under Order 704 (as defined and described below).
We anticipate those costs will continue to be incurred in the future. Occupational health and safety. We are also subject to the requirements of the federal Occupational Safety and Health Act, as amended (“OSHA”), and comparable state laws that regulate the protection of the health and safety of employees.
We anticipate those costs will continue to be incurred in the future. 18 Occupational health and safety. We are also subject to the requirements of the federal Occupational Safety and Health Act, as amended ("OSHA"), and comparable state laws that regulate the protection of the health and safety of employees.
The Oil Pollution Act of 1990, as amended (“OPA”), contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States.
The Oil Pollution Act of 1990, as amended ("OPA"), contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States.
We could become subject to these Title V and PSD permitting reviews and be required to install “best available control technology” to limit emissions of GHGs from any new or significantly modified facilities that we may seek to construct in the future if such facilities emitted volumes of GHGs in excess of threshold permitting levels.
We could become subject to these Title V and PSD permitting reviews and be required to install the best available control technology to limit emissions of GHGs from any new or significantly modified facilities that we may seek to construct in the future if such facilities emitted volumes of GHGs in excess of threshold permitting levels.
Among other matters, EPAct 2005 amends the Natural Gas Act (“NGA”) to make it unlawful for “any entity,” including otherwise non-jurisdictional producers such as Range, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by the Federal Energy Regulatory Commission (the “FERC”), in contravention of rules prescribed by the FERC.
Among other matters, EPAct 2005 amends the Natural Gas Act ("NGA") to make it unlawful for "any entity," including otherwise non-jurisdictional producers such as Range, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by the Federal Energy Regulatory Commission (the "FERC"), in contravention of rules prescribed by the FERC.
As a result, we could also become subject to additional permitting requirements and experience added delays or curtailment in the pursuit of exploration, development, or production activities. In addition, certain government reviews are underway that focus on environmental aspects of hydraulic fracturing practices.
As a result, we could also become subject to additional permitting requirements, new setback distances or experience added delays or curtailment in the pursuit of exploration, development, or production activities. In addition, certain government reviews are underway that focus on environmental aspects of hydraulic fracturing practices.
Our Appalachian production is transported on third-party pipelines on which we hold a certain amount of long-term contractual capacity. We attempt to balance sales, storage and transportation positions, which can include purchase of commodities from third parties for resale, to satisfy transportation commitments.
Our Appalachian production is transported on third-party pipelines on which we hold a certain amount of long-term contractual capacity. We attempt to balance sales, storage and transportation positions, which can include purchase of commodities from third parties for resale, to utilize contracted transportation capacity.
The Clean Air Act of 1963, as amended (the “Clean Air Act”) and comparable state laws restrict the emission of air pollutants from many sources.
The Clean Air Act of 1963, as amended (the "Clean Air Act") and comparable state laws restrict the emission of air pollutants from many sources.
Also, in June 2018, the Pennsylvania Department of Environmental Protection (“DEP”) adopted heightened permitting conditions for all newly permitted or modified natural gas compressor stations, processing plants and transmission stations constructed, modified, or operated in Pennsylvania in an effort to regulate emissions of the greenhouse gas at such sites.
Also, in June 2018, the DEP adopted heightened permitting conditions for all newly permitted or modified natural gas compressor stations, processing plants and transmission stations constructed, modified, or operated in Pennsylvania in an effort to regulate emissions of the greenhouse gas at such sites.
Although petroleum, including crude oil and natural gas, is not a “hazardous substance” under CERCLA, at least two courts have ruled that certain wastes associated with the production of crude oil may be classified as “hazardous substances” under CERCLA and that releases of such wastes may therefore give rise to liability under CERCLA.
Although petroleum, including crude oil and natural gas, is not a hazardous substance under CERCLA, at least two courts have ruled that certain wastes associated with the production of crude oil may be classified as hazardous substances under CERCLA and that releases of such wastes may therefore give rise to liability under CERCLA.
We cannot predict when or whether any such proposals may become effective. 14 In December 2007, the FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (“Order 704”).
We cannot predict when or whether any such proposals may become effective. 13 In December 2007, the FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing ("Order 704").
The effect of these factors cannot be accurately predicted or anticipated. Although we cannot predict the occurrence of events that may affect commodity prices or the degree to which commodity prices will be affected, the prices for any commodity that we produce will generally approximate current market prices in the geographic region of the production.
Although we cannot predict the occurrence of events that may affect commodity prices or the degree to which commodity prices will be affected, the prices for any commodity that we produce will generally approximate current market prices in the geographic region of the production.
The Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), also known as the “Superfund” law and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release or threatened release of a “hazardous substance” into the environment.
The Comprehensive Environmental Response, Compensation and Liability Act, as amended ("CERCLA"), also known as the Superfund law and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release or threatened release of a hazardous substance into the environment.
A well found to be incapable of producing oil or natural gas in sufficient economic quantities. Exploratory well. A well drilled to find oil or gas in an unproved area, to find a new reservoir in an existing field previously found to be productive of oil and gas in another reservoir or to extend a known reservoir.
A well found to be incapable of producing oil or natural gas in sufficient economic quantities. Exploratory well. A well drilled to find oil or natural gas in an unproved area or to find a new reservoir in an existing field previously found to be productive in another reservoir. Gross acres or gross wells.
On January 12, 2023, FERC issued a final rule increasing the maximum civil penalty for violations of the NGA from $1,388,496 per day per violation to $1,496,035 per day per violation to account for inflation pursuant to the Federal Civil Penalties Inflation Adjustment Improvement Act of 2015.
On January 11, 2024, FERC issued a final rule increasing the maximum civil penalty for violations of the NGA from $1,496,035 per day per violation to $1,544,521 per day per violation to account for inflation pursuant to the Federal Civil Penalties Inflation Adjustment Improvement Act of 2015.
Compliance with these or any similar subsequently enacted regulatory initiatives could directly impact us by requiring installation of new emission controls on some of our equipment, resulting in longer permitting timelines, and significantly increasing our capital expenditures and operating costs, which could adversely impact our business. Climate change.
Compliance with these or any similar subsequently enacted regulatory initiatives could directly impact us by requiring installation of new emission controls on 17 some of our equipment, resulting in the need for additional permitting and introducing potential permitting delays and increasing our capital expenditures and operating costs, which could adversely impact our business. Climate change.
We believe we are in substantial compliance with currently applicable laws and regulations, and the continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations.
An overview of relevant federal, state and local regulations is set forth below. We believe we are in substantial compliance with currently applicable laws and regulations, and the continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations.
In August 2005, the United States Congress (“Congress”) enacted the Energy Policy Act of 2005 (“EPAct 2005”).
In August 2005, the United States Congress ("Congress") enacted the Energy Policy Act of 2005 ("EPAct 2005").
Increases in liquids transportation rates may result in lower revenue and cash flow. In January 2022, the FERC revised the adjustment for this index to be based on Producer Price Index for Finished Goods minus 0.21% for the five year period from July 1, 2021 to June 30, 2026.
In January 2022, the FERC revised the adjustment for this index to be based on Producer Price Index for Finished Goods minus 0.21% for the five year period from July 1, 2021 to June 30, 2026. This adjustment is subject to review every five years.
In addition, pipelines, utilities, local distribution companies and industrial end-users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also impact the seasonality of demand. Mark ets Our ability to produce and market natural gas, NGLs and oil profitably depends on numerous factors beyond our control.
In addition, pipelines, utilities, local distribution companies and industrial end-users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also impact the seasonality of demand. Exports can also impact demand based on the seasonality of global markets.
This adjustment became effective on March 1, 2022 and is subject to review every five years. In addition, due to common carrier regulatory obligations of liquids pipelines, capacity must be prorated among shippers in an equitable manner in the event there are nominations in excess of capacity by current shippers or capacity requests are received from a new shipper.
In addition, due to common carrier regulatory obligations of liquids pipelines, capacity must be prorated among shippers in an equitable manner in the event there are nominations in excess of capacity by current shippers or capacity requests are received from a new shipper. Therefore, new shippers or increased volume by existing shippers may reduce the capacity available to us.
Environmental and Occupational Health and Safety Matters Our operations are subject to numerous federal, state and local laws and regulations governing occupational health and safety, the discharge of materials into the environment or otherwise relating to environmental protection, some of which carry substantial administrative, civil and criminal penalties for failure to comply.
Any prolonged interruption in the operation or curtailment of available capacity of the pipelines that we rely upon for liquids transportation could have a material adverse effect on our business, financial condition, results of operations and cash flows. 14 Environmental and Occupational Health and Safety Matters Our operations are subject to numerous federal, state and local laws and regulations governing occupational health and safety, the discharge of materials into the environment or otherwise relating to environmental protection, some of which carry substantial administrative, civil and criminal penalties for failure to comply.
Disruption and uncertainty of this sort can affect the price of oil and natural gas and may cause us to change our plans for exploration and production levels. An overview of relevant federal, state and local regulations is set forth below.
For example, in the past the United States government has imposed tariffs on certain foreign imports and the resulting retaliation by those foreign governments has disrupted aspects of the energy market. Disruption and uncertainty of this sort can affect the price of oil and natural gas and may cause us to change our plans for exploration and production levels.
Removed
For example, the decision of the United States government to impose tariffs on certain Chinese imports and the resulting retaliation by the Chinese government imposing a twenty-five percent tariff on United States’ liquefied natural gas exports have disrupted certain aspects of the energy market.
Added
Mark ets Our ability to produce and market natural gas, NGLs and oil profitably depends on numerous factors beyond our control. The effect of these factors cannot be accurately predicted or anticipated.
Removed
Despite a trade agreement with China announced in January 2020, China’s twenty-five percent tariff on imports of United States liquefied natural gas is expected to remain in place for now, but eventually could be eased by discretionary tariff exemptions granted to Chinese importers of United States liquefied natural gas or if discussions progress to a second phase agreement.
Added
For example, on July 1, 2023, oil pipelines regulated by FERC and utilizing this index system were able to increase their rates by over 13%, which amounts to the largest index rate increase since FERC initiated this methodology. Increases in liquids transportation rates may result in lower revenue and cash flow.
Removed
Therefore, new shippers or increased volume by existing shippers may reduce the capacity available to us. Any prolonged interruption in the operation or curtailment of available capacity of the pipelines that 15 we rely upon for liquids transportation could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Added
For example, in November 2023, Pennsylvania Governor Josh Shapiro instructed the Pennsylvania Department of Environmental Protection ("DEP") to take immediate action to pursue formal rulemaking 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.
Removed
States could also elect to prohibit hydraulic fracturing altogether, such as in the states of Washington, New York, Vermont, Maryland and Oregon (which temporarily suspended hydraulic fracturing until 2025). The governor of the State of California has also announced plans to ban hydraulic fracturing in that state by 2024.
Added
Certain states have prohibited hydraulic fracturing or imposed setbacks that severely limit where drilling and hydraulic fracturing can take place. Range currently does not have operations in any of those states.
Removed
For example, pursuant to then President Obama’s Strategy to Reduce Methane Emissions in August 2015, the EPA proposed new regulations that would set methane emission standards for new and modified oil and natural gas production and natural gas processing and transmission facilities.
Added
For example, on December 2, 2023, the EPA released a final rule on the New Source Performance Standards ("NSPS") to sharply reduce emissions of methane and other air pollution from oil and natural gas operations.
Removed
The EPA finalized these new regulations on June 3, 2016 to be effective August 2, 2016; however, on June 12, 2017, the EPA announced a proposed two-year stay on these fugitive emissions standards “while the agency reconsiders them.” On September 24, 2019, the EPA determined in a proposed rule that some of the requirements under the 2016 regulations and other prior rules are inappropriate because they affect sources that are not appropriately identified as part of the regulated source category and are unnecessary because they impose redundant requirements.
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The final rule, as released 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 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 proper documentation that wells are properly closed and plugged before monitoring is allowed to end.
Removed
As a result, the EPA proposed to rescind the inappropriate and redundant requirements while maintaining health and environmental protections from appropriately identified emission sources within the regulated source category.
Added
In response to feedback received during the rule's comment period, the EPA adjusted several provisions of the 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.
Removed
However, on November 2, 2021, the EPA issued a new proposed rule under the Clean Air Act aimed at reducing methane and other air pollution from both new and existing sources in the oil and natural gas industry.
Added
Further, on August 1, 2023, the EPA released a proposed rule to update the Greenhouse Gas Reporting Program for the Petroleum and Natural Gas category (subpart W). Upon finalization, this rule could potentially impact Range's greenhouse gas emissions reported to the EPA in future years.
Removed
This proposed rule (i) would require states to reduce methane emissions from hundreds of thousands of existing sources nationwide for the first time, (ii) would expand current emissions reduction requirements for new, modified and reconstructed sources in the oil and natural gas industry, and (iii) when finalized, could require the use of advanced technologies as part of the “best system of emission reduction” for leak surveys at well sites and compressor stations.
Added
For example, in August 2022, Congress enacted the Inflation Reduction Act, which among other things, adopted a methane emissions fee to be assessed against oil and gas operators. Thereafter, the EPA issued proposed rules regarding the calculation of the so-called waste emissions fee and collection of those fees.
Removed
A public comment period was held and, on November 11, 2022, the EPA issued a supplement to its November 2021 proposed rule that aims to, among other things, (i) ensure that well sites are routinely monitored for leaks, with requirements based on the type and amount of equipment on site, (ii) require the deployment of innovative and advanced monitoring 18 technologies by establishing performance requirements that can be met by a broader array of technologies, and (iii) prevent leaks from abandoned and unplugged wells by requiring documentation that well sites are properly closed and plugged before monitoring is allowed to end.
Added
While Range's methane emissions intensity remains low and below the stated threshold as currently proposed, changes to the calculation of that fee could result in fees in the future.
Removed
A public comment period was held in January 2023, with a final rule expected later in 2023. When and if these standards become implemented and exactly what they will require is still not known.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

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ITEM 7A. Quantitative and Qualitative Disclosures about Market Risk 60 Market Risk 60 Commodity Price Risk 61 Other Commodity Risk 61 Commodity Sensitivity Analysis 62 Counterparty Risk 62 Interest Rate Risk 62 ITEM 8. Financial Statements and Supplementary Data F- 1
ITEM 7A. Quantitative and Qualitative Disclosures about Market Risk 56 Market Risk 56 Commodity Price Risk 57 Other Commodity Risk 57 Commodity Sensitivity Analysis 57 Counterparty Risk 58 Interest Rate Risk 58 ITEM 8. Financial Statements and Supplementary Data F- 1

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