Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with the accompanying consolidated financial statements and notes thereto included elsewhere in this Annual Report.
The following discussion and analysis primarily focuses on 2024 and 2023 items and year-to-year comparisons between 2024 and 2023. Discussions of 2022 items and year-to-year comparisons between 2023 and 2022 that are not included in this Annual Report can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2023 Annual Report on Form 10-K filed with the SEC on February 29, 2024.
The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs, and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to several factors which include, but are not limited to market prices for oil, natural gas and NGLs, production volumes, estimates of proved reserves, capital for mineral acquisitions, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and those discussed in the sections entitled Item 1A. “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements.” We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.
Overview
As of December 31, 2024, we owned mineral and royalty interests representing approximately 273,100 NRAs when adjusted to a 1/8th royalty. For the year ended December 31, 2024, the average net daily production associated with our mineral and royalty interests was 38,517 BOE/d, consisting of 19,128 Bbls/d of oil, 64,363 Mcf/d of natural gas and 8,661 Bbls/d of NGLs. Prior to the closing of the Falcon Merger, the Company’s financial statements that were filed with the SEC were derived from the accounting records of Falcon Minerals Corporation. As such, the historical consolidated financial statements for the year ended December 31, 2022 included in this Annual Report are based on the financial statements of our predecessor, Kimmeridge Mineral Fund, LP (the “Predecessor”), prior to our corporate reorganization. Since our Predecessor’s formation in November 2016, we have accumulated our acreage position by making 209 acquisitions as of December 31, 2024. We expect to continue to grow our acreage position by making acquisitions that meet our investment criteria for geologic quality, operator capability, remaining growth potential, cash flow generation, regulatory environment, and, most importantly, rate of return.
Our mineral and royalty interests entitle us to receive a fixed percentage of the revenue from crude oil, natural gas and NGLs produced from the acreage underlying our interests. We are not obligated to fund drilling and completion costs, plugging and abandonment costs or lease operating expenses associated with oil and gas production and we incur only our proportionate share of production and ad valorem taxes and, in some cases, gathering, processing and transportation costs which reduce the amount of revenue we recognize. For the year ended December 31, 2024, our production and ad valorem taxes were approximately $3.29 per BOE, relative to an average realized price of $43.35 per BOE. We do not anticipate engaging in any upstream activities such as drilling and completing oil and natural gas wells that would incur capital costs, lease operating expenses, and plugging and abandonment costs. We believe our cost structure and business model will allow us to return a significant amount of our cash flows to stockholders.
Recent Developments
Share Repurchase Program
On February 28, 2024, our Board authorized a share repurchase program (“Share Repurchase Program”) that allows us to repurchase up to $200.0 million of our Class A Common Stock and Sitio OpCo Partnership Units. The shares may be repurchased from time to time through various methods including but not limited to in the open market transactions, through privately negotiated transactions or by other means in accordance with applicable securities laws, certain of which may be made pursuant to trading plans meeting the requirements of Rule 10b5-1 and 10b-18 under the Exchange Act. The timing of repurchases under the program, as well as the number and value of shares repurchased under the program, will be determined by the Company at its discretion and will depend on a variety of factors, including the market price of our Common Stock, oil and gas commodity prices, general market and economic conditions, available liquidity, compliance with the Company’s debt and other agreements, applicable legal requirements and other considerations. The exact number of shares to be repurchased by us is not guaranteed, and the program may be modified, suspended or discontinued at any time without prior notice. The Company is not obligated to repurchase any dollar amount or number of shares under the program.
For the year ended December 31, 2024, the Company repurchased 4,224,814 shares of its Class A Common Stock in connection with the Share Repurchase Program. The shares were recorded at a weighted average price of $22.72, upon repurchase by the Company, inclusive of third-party commissions.
For the year ended December 31, 2024, the Company repurchased and immediately canceled 897,457 Sitio OpCo Partnership Units together with an equivalent number of shares of Class C Common Stock under our Share Repurchase Program. The repurchased Sitio OpCo Partnership Units were recorded at a weighted average price of $24.67.
The IRA 2022 provides for, among other things, the imposition of a 1% non-deductible U.S. federal excise tax on the fair market value of any stock repurchased by a publicly traded domestic corporation during any taxable year, with the fair market value of such repurchased stock reduced by the fair market value of certain stock issued by such corporation during such taxable year (such excise tax, the “Stock Buyback Tax”). In the past, there have been proposals to increase the amount of the Stock Buyback Tax from 1% to 4%; however, it is unclear whether such a change in the amount of the excise tax will be enacted and, if enacted, how soon any such change could take effect. The Stock Buyback Tax first applied to our Share Repurchase Program in the year ended December 31, 2024, and will continue to apply in subsequent taxable years.
Revolving Credit Facility
On February 3, 2023, Sitio OpCo, as borrower, and certain of its subsidiaries as guarantors entered into the Third Amended and Restated Credit Agreement (as amended, restated, supplemented or otherwise modified from time to time, the “Sitio Revolving Credit Facility”) among JPMorgan Chase Bank, N.A., as the administrative agent and as issuing bank, and the Lenders, which amended, restated and refinanced in its entirety the RBL Credit Agreement (defined below). On December 16, 2024, Sitio OpCo and the other guarantors party thereto entered into that certain Fourth Amendment to Third Amended and Restated Credit Agreement, pursuant to which the Sitio Credit Agreement was amended to (i) effectuate the scheduled redetermination of the borrowing base intended to be effective on or about November 1, 2024 by increasing the borrowing base under the Sitio Revolving Credit Facility (the “Sitio Borrowing Base”) to $925,000,000, (ii) increase the elected commitment amount to $925,000,000 and (iii) amend certain other terms of the Sitio Credit Agreement, in each case, on the terms and subject to the conditions set forth therein. At December 31, 2024, the Sitio Borrowing Base, as determined by the Lenders, was $925.0 million and the outstanding balance under the Sitio Revolving Credit Facility was $487.8 million.
Acquisitions
For the year ended December 31, 2024, Sitio completed multiple acquisitions totaling approximately 20,600 NRAs in the Delaware, DJ and Midland Basins.
As of December 31, 2024, we have evaluated over 1,000 potential mineral and royalty interest acquisitions and completed 209 acquisitions from landowners and other mineral interest owners. We intend to capitalize on our management team’s expertise and relationships to continue to make value-enhancing mineral and royalty interest acquisitions in premier basins designed to increase our cash flows per share.
Production and Operations
Our average daily production during the years ended December 31, 2024, 2023, and 2022 was 38,517 BOE/d (50% crude oil), 35,457 BOE/d (49% crude oil), and 15,204 BOE/d (52% crude oil), respectively. For the year ended December 31, 2024, we received an average of $75.26 per Bbl of crude oil, $1.02 per Mcf of natural gas and $18.99 per Bbl of NGLs, for an average realized price of $43.35 per BOE. For the year ended December 31, 2023, we received an average of $75.80 per Bbl of crude oil, $1.77 per Mcf of natural gas and $19.21 per Bbl of NGLs, for an average realized price of $44.39 per BOE. For the year ended December 31, 2022, we received an average of $93.05 per Bbl of crude oil, $5.50 per Mcf of natural gas and $33.51 per Bbl of NGLs, for an average realized price of $64.05 per BOE.
As of December 31, 2024, we had 47,317 gross (361.7 net) producing horizontal wells on our acreage. Additionally, as of December 31, 2024, there were 5,047 gross (24.5 net) horizontal wells in various stages of drilling or completion and 3,598 active (20.4 net) horizontal drilling permits on our acreage. As of December 31, 2023, we had 36,915 gross (281.6 net) producing horizontal wells on our acreage. Additionally, as of December 31, 2023, there were 4,086 gross (31.1 net) horizontal wells in various stages of drilling or completion and 3,323 gross (17.3 net) active horizontal drilling permits on our acreage. As of December 31, 2022, we had 32,451 gross (239.9 net) producing horizontal wells on our acreage. Additionally, as of December 31, 2022, there were 4,254 gross (31.1 net) horizontal wells in various stages of drilling or completion and 3,223 (16.8 net) active horizontal drilling permits on our acreage.
Economic Indicators
The economy has experienced elevated inflation levels in recent years. In order to manage the inflation risk in the United States’ economy, the Federal Reserve has utilized monetary policy in the form of elevated interest rates in an effort to decrease inflation on a long-term basis. Our exposure to the impact of interest rates is attributable to balances outstanding on the Sitio Revolving Credit Facility and any potential new debt issuances. Our 2028 Senior Notes are not exposed to interest rate movements as the coupon rate on our 2028 Senior Notes is fixed.
Inflationary pressures could result in increases to our operating expenses that are not fixed such as personnel retention, among other things. Increases in interest rates as a result of inflation and a potentially recessionary economic environment in the United States could also have a negative effect on the demand for oil and natural gas, as well as our borrowing costs. While inflationary pressures in the United States' economy have begun to subside and the Federal Reserve has recently lowered the federal funds rate, we continue to be impacted by the elevated level of interest rates as compared to recent years. Although the Federal Reserve made cuts to benchmark interest rates in 2024 and there is a possibility of additional cuts, there is no guarantee that such additional cuts will occur. Any subsequent increases in benchmark interest rates could have the effect of further raising our borrowing costs.
There is currently significant uncertainty about the future relationship between the United States and various other countries, including changes arising as a result of the new presidential administration, with respect to trade policies, treaties, tariffs, taxes, and other limitations on cross-border operations. Changes in tariffs, trade barriers, price and exchange controls and other regulatory requirements could have an adverse effect on our business, prospects, financial condition and operation results, the extent of which cannot be predicted with certainty at this time.
The global economy also continues to be impacted by geopolitical events such as the February 2022 launch of a large-scale invasion of Ukraine by Russia, the conflict in the Israel-Gaza region and increases in hostilities elsewhere in the Middle East, including tensions with Iran, Lebanon and Yemen. It has also has been impacted by, among other events, the uncertainty regarding global central bank monetary policy. The geopolitical and macroeconomic consequences of the Russian invasion of Ukraine and associated sanctions, the conflict in the Israel-Gaza region and elsewhere in the Middle East, and the uncertainty regarding central bank monetary policy cannot be predicted, and such events, or any escalation of hostilities in Ukraine or the Middle East, or further hostilities elsewhere, could severely impact the world economy and may adversely affect our financial condition. The oil and natural gas industry has also been impacted by announcements of voluntary production cuts by OPEC and others, including OPEC’s recent extensions of its voluntary production cuts. These events and their impacts on the global economy continue to evolve, and the extent to which these events may impact our business, financial condition, liquidity, results of operations, and prospects will depend highly on future developments, which are very uncertain and cannot be predicted with confidence.
How We Evaluate Our Operations
We use a variety of operational and financial measures to assess our performance. Among the measures considered by management are the following:
• volumes of oil, natural gas and NGLs produced;
• number of producing wells, spud wells and permitted wells;
• commodity prices;
• Adjusted EBITDA; and
• Discretionary Cash Flow.
Volumes of Oil, Natural Gas and NGLs Produced
In order to track and assess the performance of our assets, we monitor and analyze our production volumes from our mineral and royalty interests. We also regularly compare projected volumes to actual reported volumes and investigate unexpected variances.
Producing Wells, Spud Wells and Permitted Wells
In order to track and assess the performance of our assets, we also constantly monitor the number of permitted wells, spud wells, completions, and producing wells on our mineral and royal interests in an effort to evaluate near-term production growth.
Commodity Prices
Historically, oil, natural gas and NGL prices have been volatile and may continue to be volatile in the future. During the past five years, the posted price for WTI has ranged from a low of negative $36.98 per barrel in April 2020 to a high of $123.64 per barrel in March 2022. The Henry Hub spot market price for natural gas has ranged from a low of $1.21 per MMBtu in November 2024 to a high of $23.86 per MMBtu in February 2021. Lower prices may not only decrease our revenues, but also potentially the amount of oil, natural gas and NGLs that our operators can produce economically.
Oil . The substantial majority of our oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of our control. The majority of our oil production is priced at the prevailing market price with the final realized price affected by both quality and location differentials.
The chemical composition of crude oil plays an important role in its refining and subsequent sale as petroleum products. As a result, variations in chemical composition relative to the benchmark crude oil, usually WTI, will result in price adjustments, which are often referred to as quality differentials. The characteristics that most significantly affect quality differentials include the density of the oil, as characterized by its API gravity, and the presence and concentration of impurities, such as sulfur.
Location differentials generally result from transportation costs based on the produced oil’s proximity to consuming and refining markets and major trading points.
Natural Gas . The New York Mercantile Exchange, Inc. (“NYMEX”) price quoted at Henry Hub is a widely used benchmark for the pricing of natural gas in the United States. The actual prices realized from the sale of natural gas differ from the quoted NYMEX price as a result of quality and location differentials.
Quality differentials result from the heating value of natural gas measured in Btu and the presence of impurities, such as hydrogen sulfide, carbon dioxide and nitrogen. Natural gas containing ethane and heavier hydrocarbons has a higher Btu value and will realize a higher volumetric price than natural gas that is predominantly methane, which has a lower Btu value. Natural gas with a higher concentration of impurities will realize a lower price due to the presence of the impurities in the natural gas when sold or the cost of treating the natural gas to meet pipeline quality specifications.
Natural gas, which currently has limitations on transportation in certain regions, is subject to price variances based on local supply and demand conditions and the cost to transport natural gas to end-user markets.
NGLs . NGL pricing is generally tied to the price of oil, but varies based on differences in liquid components and location.
Non-GAAP Financial Measures
Adjusted EBITDA
Adjusted EBITDA is a non-GAAP supplemental financial measure used by our management and by external users of our financial statements such as investors, research analysts and others to assess the financial performance of our assets and their ability to sustain dividends over the long term.
We define Adjusted EBITDA as net income (loss) plus (a) interest expense, (b) provisions for income taxes, (c) depreciation, depletion and amortization, (d) non-cash share-based compensation expense, (e) impairment of oil and gas properties, (f) gains or losses on unsettled derivative instruments, (g) change in fair value of warrant liability, (h) management fee to affiliates, (i) loss on extinguishment of debt (j) merger-related transaction costs, (k) write off of financing costs, and (l) loss on sale of oil and gas properties. Adjusted EBITDA is not a measure determined by GAAP.
This non-GAAP financial measure does not represent and should not be considered an alternative to, or more meaningful than, its most directly comparable GAAP financial measure or any other measure of financial performance presented in accordance with GAAP as measures of our financial performance. Non-GAAP financial measures have important limitations as analytical tools because they exclude some but not all items that affect the most directly
comparable GAAP financial measure. Our computation of Adjusted EBITDA may differ from computations of similarly titled measures of other companies.
Discretionary Cash Flow
Discretionary Cash Flow is a non-GAAP supplemental financial measure used by our management and by external users of our financial statements such as investors, research analysts and others to assess the financial performance of our assets and their ability to sustain dividends over the long term.
We define Discretionary Cash Flow in 2024 as Adjusted EBITDA, less cash and accrued interest expense and estimated cash taxes.
We define Discretionary Cash Flow for the three months ended December 31, 2023 as Adjusted EBITDA, less cash and accrued interest expense and cash taxes. We revised our definition of Discretionary Cash Flow following this period to reflect our anticipated accrual of taxes period-to-period due to the runoff of tax credits associated with the Brigham Merger.
We define Discretionary Cash Flow for time periods ended prior to December 31, 2023 as Adjusted EBITDA, less cash interest expense and cash taxes. We revised our definition of Discretionary Cash Flow following these periods to reflect quarterly accrual of interest expense on the then-newly issued 2028 Senior Notes, which interest is paid semi-annually. Discretionary Cash Flow is not a measure determined by GAAP.
This non-GAAP financial measure does not represent and should not be considered an alternative to, or more meaningful than, its most directly comparable GAAP financial measure or any other measure of financial performance presented in accordance with GAAP as measures of our financial performance. Non-GAAP financial measures have important limitations as analytical tools because they exclude some but not all items that affect the most directly comparable GAAP financial measure. Our computation of Discretionary Cash Flow may differ from computations of similarly titled measures of other companies.
Cash G&A
We define Cash G&A as general and administrative expense less (a) non-cash share-based compensation expense, (b) merger-related transaction costs and (c) rental income.
This non-GAAP financial measure does not represent and should not be considered an alternative to, or more meaningful than, its most directly comparable GAAP financial measure or any other measure of financial performance presented in accordance with GAAP as measures of our financial performance. Non-GAAP financial measures have important limitations as analytical tools because they exclude some but not all items that affect the most directly comparable GAAP financial measure. Our computation of Cash G&A may differ from computations of similarly titled measures of other companies.
Sources of Revenue
Our revenues are primarily derived from mineral and royalty payments received from our E&P operators based on the sale of crude oil, natural gas and NGLs production from our interests. Our revenues may vary significantly from period to period because of changes in commodity prices, production mix and volumes of production sold by our E&P operators. For the years ended December 31, 2024, 2023 and 2022, mineral and royalty revenue made up 98%, 97% and 96%, respectively, of our total revenues. As a result of our royalty income production mix, our income is more sensitive to fluctuations in crude oil prices than it is to fluctuations in natural gas or NGLs prices. Crude oil, natural gas and NGL prices have historically been volatile, and we expect this volatility to continue. Additionally, we earn lease bonus income by leasing our mineral interests to exploration and production companies and income from delay rentals and easements.
The following table presents the breakout of our revenues for the following periods:
Year Ended December 31,
Crude oil sales
Natural gas sales
NGL sales
Lease bonus and other income
Total revenues
Principal Components of Our Cost Structure
The following is a description of the principal components of our cost structure. As a mineral and royalty owner, we incur only our proportionate share of production and ad valorem taxes and, in some cases, gathering, processing and transportation costs, which reduce the amount of revenue we recognize. Unlike E&P operators and owners of working interests in oil and gas properties, we are not obligated to fund drilling and completion costs, plugging and abandonment costs or lease operating expenses associated with oil and gas production.
Production and Ad Valorem Taxes
Production taxes are paid at fixed rates on produced crude oil, natural gas, and NGLs based on a percentage of revenues from our volume of products sold, established by federal, state or local taxing authorities. The E&P companies who operate on our interests withhold and pay our pro rata share of production taxes on our behalf. We directly pay ad valorem taxes in the counties where our properties are located. Ad valorem taxes are generally based on the appraised value of our crude oil, natural gas and NGLs properties.
General and Administrative
General and administrative expenses consist of costs incurred related to overhead, including executive and other employee compensation and related benefits, office expenses and fees for professional services such as audit, tax, legal and other consulting services. During the year ended December 31, 2022, some of those costs were incurred on our behalf by the Predecessor’s general partner and its affiliates and reimbursed by the Predecessor. For example, the Predecessor reimbursed an affiliate of its general partner for personnel costs on our behalf. As a result of the Falcon Merger, we incur incremental general and administrative expenses relating to SEC reporting requirements, including annual and quarterly reports, increased tax return preparation expenses, Sarbanes-Oxley Act compliance expenses, expenses associated with listing our Class A Common Stock, increased independent auditor fees, increased legal expenses and investor relations expenses. These incremental general and administrative expenses are not reflected in the Predecessor financial statements.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization (“DD&A”) is the systematic expensing of capitalized costs. Under the successful efforts method of accounting, capitalized costs of our proved crude oil, natural gas and NGLs mineral interest properties are depleted on a unit-of-production basis based on proved crude oil, natural gas and NGLs reserve quantities. Our estimates of crude oil, natural gas and NGLs reserves are, by necessity, projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production. Any significant variance in the assumptions could materially affect the estimated quantity of the reserves, which could affect the rate of depletion related to our crude oil, natural gas and NGLs properties. DD&A also includes the expensing of office leasehold costs and equipment.
Interest Expense
We have financed a portion of our working capital requirements and acquisitions with borrowings under our revolving credit facilities, the 2026 Senior Notes (which were retired in October 2023), and the 2028 Senior Notes. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to the lenders under our revolving credit facilities, the 2026 Senior Notes, the 2028 Senior Notes, and amortization of debt issuance costs in interest expense in our consolidated statements of operations.
Income Tax Expense
As a corporation, we are subject to U.S. federal income taxes. We are also subject to the Texas margin tax, which is a state franchise tax, and certain state income taxes.
Factors Affecting the Comparability of Our Financial Results
Our future results of operations may not be comparable to our Predecessor’s results of operations for the periods presented, primarily for the reasons described below.
Acquisitions
Our and our Predecessor’s financial statements for the year ended December 31, 2022 do not include the results of operations for the assets acquired in the Chambers acquisition, Rock Ridge acquisition, Source acquisition, the Falcon Merger, Foundation acquisition, Momentum acquisition, and Brigham Merger (described in “Note 7 – Acquisitions and Divestitures” included elsewhere in this Form 10-K) prior to the respective dates of acquisition. As a result, our Predecessor’s financial results do not give an accurate indication of what the actual results would have been if such acquisitions had been completed at the beginning of the periods presented or of what our future results are likely to be.
In addition, we plan to pursue potential accretive acquisitions of additional mineral and royalty interests. We believe we will be well positioned to acquire such assets and, should such opportunities arise, identifying and executing acquisitions will be a key part of our strategy. However, if we are unable to make acquisitions on economically acceptable terms, our future growth may be limited, and any acquisitions we may make may reduce, rather than increase, our cash flows and ability to pay dividends to stockholders in the short-term.
Debt and Interest Expense
As a public company, we may finance a portion of our acquisitions with borrowings under the Sitio Revolving Credit Facility or other debt instruments. As a result, we will incur interest expense that is affected by both fluctuations in interest rates and our financing decisions.
Public Company Expenses
We incur incremental general and administrative expenses as a result of operating as a publicly traded company, such as expenses associated with SEC reporting requirements, including annual and quarterly reports, Sarbanes-Oxley Act compliance expenses, expenses associated with listing our Class A Common Stock, increased independent auditor fees, independent reserve engineer fees, increased legal fees, investor relations expenses, registrar and transfer agent fees, director and officer insurance expenses and director and officer compensation expenses. These incremental general and administrative expenses are not reflected in our Predecessor’s financial statements. Additionally, as a result of the Falcon Merger and Brigham Merger, we have hired additional employees, including accounting, engineering and land personnel, in order to comply with requirements of being a publicly traded company.
Income Taxes
We are subject to U.S. federal and state income taxes as a corporation. The Predecessor was generally not subject to U.S. federal income tax at the entity level. As such, our Predecessor’s financial statements did not contain a provision for U.S. federal income taxes. The only tax expense that appeared in our Predecessor’s financial statements was the Texas margin tax and certain state income taxes, to which we continue to be subject as a corporation.
Surface Rights
The Predecessor’s historical consolidated financial statements are based on our financial statements prior to the Falcon Merger. The assets acquired in connection with the Falcon Merger did not include the Predecessor’s surface rights, which generate revenue from the sale of water, payments for rights-of-way and other rights associated with the ownership of the surface acreage, which are included in our Predecessor’s historical financial statements but were not contributed to the post-combination company following the closing of the Falcon Merger. Subsequent to the Falcon Merger, we have acquired additional surface rights in connection with multiple acquisitions. As a result, the historical consolidated financial data may not give you an accurate indication of what the actual results would have been if the Falcon Merger had been completed at the beginning of the periods presented or of what our future results of operations are likely to be.
Management Fees
The Predecessor incurred and paid annual fees under an investment management agreement with Kimmeridge Energy Management Company, LLC, an affiliate of Kimmeridge, of which Noam Lockshin, Sitio’s Chairman, is a managing member. Fees incurred under the agreement totaled approximately $3.2 million for the year ended December 31, 2022. No such fees were incurred for the years ended December 31, 2024 and 2023 or will be incurred in the future.
Results of Operations
Year Ended December 31, 2024 Compared to the Year Ended December 31, 2023
Consolidated Results
The following tables summarize our consolidated revenue and expenses and production data for the years ended December 31, 2024 and 2023 (in thousands):
Year Ended
December 31,
Variance
Statement of Operations Data:
Revenue:
Crude oil revenue
Natural gas revenue
NGLs revenue
Lease bonus
Other revenue
Total revenues
Operating Expenses:
Depreciation, depletion and amortization
General and administrative
Production taxes and other
Impairment of oil and gas properties
Loss on sale of oil and gas properties
Total operating expenses
Net income from operations
Interest expense, net (1)
Change in fair value of warrant liability
Loss on extinguishment of debt
Commodity derivatives gains (losses)
Interest rate derivatives gains
Net income (loss) before taxes
Income tax benefit (expense)
Net income (loss)
Net (income) loss attributable to noncontrolling interest
Net income (loss) attributable to Class A stockholders
(1) Interest expense is presented net of interest income.
* Not applicable or meaningful
Year Ended
December 31,
Variance
Production Data:
Crude oil (MBbls)
Natural gas (MMcf)
NGLs (MBbls)
Total (MBOE)(6:1)
Average daily production (BOE/d)(6:1)
Average Realized Prices:
Crude oil (per Bbl)
Natural gas (per Mcf)
NGLs (per Bbl)
Combined (per BOE)
Average Realized Prices After Effects of Derivative Settlements:
Crude oil (per Bbl)
Natural gas (per Mcf)
NGLs (per Bbl)
Combined (per BOE)
Revenue
Our consolidated revenues for the year ended December 31, 2024 increased as compared to the year ended December 31, 2023. The increase in revenues was primarily due an increase in oil and NGL revenues, partially offset by a decrease in natural gas and lease bonus revenues. The increase in mineral and royalty revenues was primarily due to an increase in our production volumes of 9% from the acquisitions of additional mineral and royalty interests and from our existing interests, partially offset by the sale of certain non-core properties in December 2023.
Oil revenue for the year ended December 31, 2024 increased as compared to the year ended December 31, 2023 due to a 10% increase in oil production volumes, partially offset by a 1% decrease in our average realized oil price.
Natural gas revenue for the year ended December 31, 2024 decreased as compared to the year ended December 31, 2023 due to a 42% decrease in our average realized natural gas price, partially offset by a 2% increase in production volumes. The decrease in our average realized price for natural gas was largely due to pipeline capacity constraints in the Permian Basin in 2024, which caused downward pressure on natural gas prices in the region.
NGLs revenue for the year ended December 31, 2024 increased as compared to the year ended December 31, 2023 due to a 16% increase in NGLs production volumes, partially offset by a 1% decrease in our average realized NGLs price.
Lease bonus revenue decreased for the year ended December 31, 2024 as compared to the year ended December 31, 2023. When we lease our acreage to an E&P operator, we generally receive a lease bonus payment at the time a lease is executed. These bonus payments are subject to significant variability from period to period based on the particular tracts of land that become available for releasing.
Other revenues include payments for right-of-way and surface damages, which are also subject to significant variability.
Operating Expenses
Depreciation, depletion and amortization expense increased for the year ended December 31, 2024 as compared to the year ended December 31, 2023. The increase was due to a 9% increase in year-over-year production volumes as well as a higher depletion rate, which increased from $22.47 per BOE for the year ended December 31, 2023 to $22.68 per BOE for the year ended December 31, 2024.
General and administrative expense increased for the year ended December 31, 2024 as compared to the year ended December 31, 2023. The increase was primarily due to $7.8 million of additional employee compensation and benefits due to increased share-based compensation expenses as a result of more outstanding share-based compensation awards, as well as an increase in headcount. These increases were partially offset by a decrease in merger-related transaction costs of $2.7 million.
Production taxes and other decreased slightly for the year ended December 31, 2024 as compared to the year ended December 31, 2023. The decrease was primarily due to a decrease in ad valorem taxes in 2024, which was offset by an increase in severance taxes due to the increase in oil, natural gas and NGLs revenues.
During the year ended December 31, 2023, the Company recognized impairment expense of $25.6 million attributable to its proved properties in the Appalachian Basin due to a decrease in natural gas and NGLs prices. No such expense was recognized by the Company for the year ended December 31, 2024.
Loss on sale of oil and gas properties was $144.5 million for the year ended December 31, 2023, whereas there was no loss on sale of oil and gas properties recognized for the year ended December 31, 2024. During the year ended December 31, 2023, the Company divested all of its mineral and royalty interests in the Appalachian and Anadarko Basins for $113.3 million, net of third-party transaction costs. The assets sold had a carrying value of $257.8 million.
Other Income and Expenses
Interest expense relates to interest incurred on borrowings under our revolving credit facilities, the 2028 Senior Notes and the 2026 Senior Notes. The decrease for the year ended December 31, 2024 as compared to the year ended December 31, 2023 was primarily due to a lower average interest rate incurred on our 2028 Senior Notes during the year ended December 31, 2024 as compared to the interest rates incurred on our 2026 Senior Notes during the year ended December 31, 2023.
For the year ended December 31, 2023 losses on extinguishment of debt totaled $21.6 million. No such expense was incurred for the year ended December 31, 2024. During the year ended December 31, 2023, $1.5 million of previously capitalized deferred financing costs were written off for certain lenders that did not elect to remain a party to the Sitio Revolving Credit Facility in connection with amendments in February and September 2023. The Company redeemed and repaid the 2026 Senior Notes in full during the year ended December 31, 2023 and incurred an additional loss on extinguishment of $20.1 million related to the write-off of unamortized debt issuance costs and debt discount and a redemption premium of 3.0%.
Commodity derivatives losses totaled $4.9 million for the year ended December 31, 2024 as compared to gains of $15.2 million for the year ended December 31, 2023. The decrease of $20.1 million for the year ended December 31, 2024 as compared to the year ended December 31, 2023 is due to a decrease in volumes outstanding under our commodity swaps and two-way collar contracts as of December 31, 2024 as compared to December 31, 2023, as well as changes in commodity prices.
Interest rate derivative gains totaled $462,000 for the year ended December 31, 2023. There were no interest rate derivatives for the year ended December 31, 2024. In 2022, we entered into an interest rate swap to manage exposures to changes in interest rates from variable rate borrowings. The interest rate swap expired on December 31, 2023.
Income taxes changed from a benefit of $14.3 million for the year ended December 31, 2023 to an expense of $17.9 million for the year ended December 31, 2024. This was primarily due to the recognition of a pre-tax net loss for the year ended December 31, 2023 as compared to pre-tax net income for the year ended December 31, 2024.
For a discussion of our results of operations for the year ended December 31, 2023 as compared to the year ended December 31, 2022, see Part II, Item 7, “Management's Discussion and Analysis of Financial Condition and Results of Operations” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2023 filed with the SEC on February 29, 2024.
Overview
Prior to the completion of the Falcon Merger, our Predecessor’s primary sources of liquidity were contributions of capital from its limited partners, cash flows from operations and borrowings under our revolving credit facility. After the closing of the Falcon Merger, cash flows from operations and borrowings under the Sitio Revolving Credit Facility, the 2026 Senior Notes, and the 2028 Senior Notes are the primary day-to-day sources of our funds. Future sources of liquidity
may also include other credit facilities we may enter into in the future and additional issuances of debt or equity securities. Our primary uses of cash have been, and are expected to continue to be, the acquisition of mineral and royalty interests, the reduction of outstanding debt balances and the payment of dividends and distributions. Our ability to generate cash is subject to several factors, some of which are beyond our control, including commodity prices and general economic, financial, legislative, regulatory and other factors.
We believe internally generated cash flows from operations, available borrowing capacity under the Sitio Revolving Credit Facility, and access to capital markets will provide us with sufficient liquidity and financial flexibility to meet our cash requirements, including normal operating needs, debt service obligations, our return of capital program, and capital expenditures, for at least the next 12 months and allow us to continue to execute our strategy of acquiring attractive mineral and royalty interests that will position us to grow our cash flows and return capital to our stockholders. As an owner of mineral and royalty interests, we incur the initial cost to acquire our interests but thereafter do not incur any development or maintenance capital expenditures, which are entirely borne by the E&P operator and the other working interest owners. As a result, our only capital expenditures are related to our acquisition of additional mineral and royalty interests, and we have no subsequent capital expenditure requirements related to acquired properties. The amount and allocation of future acquisition-related capital expenditures will depend upon a number of factors, including the number and size of acquisition opportunities, our cash flows from operating, investing and financing activities and our ability to integrate acquisitions. We periodically assess changes in current and projected cash flows, acquisition and divestiture activities, and other factors to determine the effects on our liquidity. Our ability to generate cash is subject to a number of factors, many of which are beyond our control, including commodity prices, weather and general economic, financial and competitive, legislative, regulatory and other factors. If we require additional capital for acquisitions or other reasons, we may raise such capital through additional borrowings, asset sales, offerings of equity and debt securities or other means. If we are to obtain funds needed or on acceptable terms, we may not be to complete acquisitions that are to us.
As of December 31, 2024, our liquidity was $440.5 million, comprised of $3.3 million of cash and cash equivalents and $437.2 million of availability under the Sitio Revolving Credit Facility.
Cash Flows for the Year Ended December 31, 2024 Compared to the Year Ended December 31, 2023 (in thousands):
Year Ended
December 31,
Variance
Statement of Cash Flows Data:
Net cash provided by (used in):
Operating activities
Investing activities
Financing activities
Net increase (decrease) in cash and cash equivalents
Operating Activities
Our operating cash flows are impacted by the variability in our revenues and operating expenses, as well as the timing of the related cash receipts and disbursements. Royalty payments may vary significantly from period to period as a result of changes in commodity prices, production mix and volumes of production sold by our E&P operators, as well as the timeliness and accuracy of payments from our E&P operators. These factors are beyond our control and are difficult to predict. Cash flows provided by operating activities for the year ended December 31, 2024 were $462.4 million as compared to $487.5 million for the year ended December 31, 2023. The decrease was primarily a result of variability in timing of cash receipts for our royalty revenue.
Investing Activities
Cash flows used in investing activities totaled $330.0 million for the year ended December 31, 2024 as compared to $59.7 million for the year ended December 31, 2023, an increase of $270.2 million due to acquisitions of oil and gas properties, net of purchase price adjustments. Our expenditures for purchases of oil and gas properties were $329.9 million for the year ended December 31, 2024, as compared to $170.5 million for the year ended December 31, 2023, an increase
of $159.3 million. We realized a net increase in cash of $113.3 million during the year ended December 31, 2023 due to the sale of our mineral and royalty interests in the Appalachian and Anadarko Basins.
Financing Activities
Cash flows used in financing activities for the year ended December 31, 2024 totaled $144.4 million as compared to cash flows used in financing activities of $431.4 million for the year ended December 31, 2023. Borrowings under our credit facilities for the years ended December 31, 2024 and 2023 were $474.4 million and $644.5 million, respectively, which were used to fund acquisitions of mineral and royalty interests. Repayments on our credit facilities for the years ended December 31, 2024 and 2023 were $263.6 million and $877.5 million, respectively, largely provided by cash flows from operations as well as from divestitures of oil and gas properties during the year ended December 31, 2023. During the year ended December 31, 2023, we received gross proceeds of $600.0 million from the issuance of the 2028 Senior Notes, which were used to repay and extinguish the 2026 Senior Notes and for other general corporate purposes. During the year ended December 31, 2024 we had a $40.7 million decrease in dividends paid to holders of Class A Common Stock and a $46.5 million decrease in distributions paid to noncontrolling interest holders. These decreases were offset by $117.4 million in repurchases of Class A Common Stock and Sitio OpCo Partnership Units during the year ended December 31, 2024, whereas there were no repurchases in 2023. Financing cash outflows during the year ended December 31, 2024 also included $2.4 million related to cash paid for taxes related to net settlement of share-based compensation awards, and $1.2 million of dividend equivalent rights.
Financing cash outflows during the year ended December 31, 2023 included $22.1 million of debt issuance costs incurred in connection with amendments and restatements to the Sitio Revolving Credit Facility and issuance of the 2028 Senior Notes, $12.2 million of debt extinguishment costs incurred in connection with the redemption of the 2026 Senior Notes, dividends of $162.0 million paid to holders of Class A Common Stock, $159.0 million of distributions paid to noncontrolling interest, $3.4 million related to cash paid for taxes related to net settlement of share-based compensation awards, and $1.0 million of dividend equivalent rights.
For a discussion of our cash flows for the year ended December 31, 2023 as compared to the year ended December 31, 2022, see Part II, Item 7, “Management's Discussion and Analysis of Financial Condition and Results of Operations” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2023 filed with the SEC on February 29, 2024.
Sitio Revolving Credit Facility
On February 3, 2023, Sitio OpCo, as borrower, and certain of its subsidiaries as guarantors entered into the Sitio Revolving Credit Facility among JPMorgan Chase Bank, N.A., as the administrative agent and as issuing bank, and the Lenders, which amended, restated and refinanced in its entirety the Second Amended and Restated Credit Agreement, led by Bank of America, N.A. as Administrative Agent, Issuing Bank and Syndication Agent (the “RBL Credit Agreement”). The availability under the Sitio Credit Revolving Credit Facility, including availability for letters of credit, is generally limited to a borrowing base, which is determined by the required number of Lenders in good faith by calculating a loan value of the proved reserves of Sitio OpCo and its subsidiaries and elected commitments provided by the Lenders. As part of the aggregate commitments under the revolving advances, the Sitio Revolving Credit Facility provides for letters of credit to be issued at the request of the borrower in an aggregate amount not to exceed $15.0 million.
As of December 31, 2024, the Sitio Borrowing Base as determined by the Lenders was $925.0 million and the outstanding balance under the Sitio Revolving Credit Facility was $487.8 million. As of December 31, 2023, the Sitio Borrowing Base as determined by the Lenders was $850.0 million and the outstanding balance under the Sitio Revolving Credit Facility was $277.0 million.
The Sitio Revolving Credit Facility bears interest at a rate per annum equal to, at our option, at an adjusted Term SOFR rate or a base rate, plus an applicable margin and credit spread adjustment. The applicable margin is based on utilization of the Sitio Revolving Credit Facility and ranges from (a) in the case of adjusted base rate loans, 1.500% to 2.500% and (b) in the case of Term SOFR rate loans and letters of credit, 2.500% to 3.500%. The credit spread adjustment for Term SOFR rate loans ranges from 0.100% to 0.250% depending on the applicable interest rate period. Sitio OpCo may elect an interest period of one, three or six months. Interest is payable in arrears at the end of each interest period, but no less frequently than quarterly. A commitment fee is payable quarterly in arrears on the daily undrawn available commitments under the Sitio Revolving Credit Facility in an amount ranging from 0.375% to 0.500% based on utilization of the Sitio Revolving Credit Facility. The Sitio Revolving Credit Facility is subject to other customary fee, interest, and expense reimbursement provisions.
As of December 31, 2024 and 2023, the weighted average interest rate related to our outstanding borrowings under the Sitio Revolving Credit Facility was 7.50% and 8.21%, respectively. As of December 31, 2024 and 2023, the Company had unamortized debt issuance costs of $8.5 million and $11.2 million, respectively, in connection with its entry into the Sitio Revolving Credit Facility, including amendments. Such costs are capitalized as deferred financing costs within other long-term assets and are amortized over the life of the facility. For the years ended December 31, 2024, 2023 and 2022, the Company recognized $3.2 million, $2.9 million, and $1.2 million, respectively, in interest expense related to the amortization of deferred financing costs under its revolving credit facilities. In connection with the amendment and restatement of the Sitio Revolving Credit Facility in February 2023 and the First Amendment to Third Amended and Restated Credit Agreement in September 2023, certain lenders did not elect to remain a party to the Sitio Revolving Credit Facility. As such, $1.5 million of previously capitalized deferred financing costs were written off to Loss on debt extinguishment during the year ended December 31, 2023.
The Sitio Revolving Credit Facility matures on June 30, 2027. Loans drawn under the Sitio Revolving Credit Facility may be prepaid at any time without premium or penalty (other than customary breakage costs for Term SOFR rate loans) and must be prepaid in the event that exposure exceeds the lesser of the Sitio Borrowing Base and the elected commitments of the Lenders at such time. The principal amount of loans that are prepaid are required to be accompanied by accrued and unpaid interest and fees on such amounts. Loans that are prepaid may be reborrowed, subject to compliance with the Sitio Revolving Credit Facility. In addition, Sitio OpCo may permanently reduce or terminate in full the commitments under the Sitio Revolving Credit Facility prior to maturity. Any excess exposure resulting from such permanent reduction or termination must be prepaid and may not be reborrowed. Upon the occurrence of an event of default under the Sitio Revolving Credit Facility, the administrative agent acting at the direction of the Lenders holding a majority of the aggregate commitments at such time may accelerate outstanding loans and terminate all commitments under the Sitio Revolving Credit Facility, provided that such acceleration and occurs automatically upon the occurrence of a or event of .
The Sitio Revolving Credit Facility is subject to a borrowing base established by the Lenders to reflect the loan value of our oil and gas mineral interests. The Sitio Borrowing Base is redetermined by the Lenders on a semi-annual basis. Additionally, Lenders holding two-thirds of the aggregate commitments are able to request one additional redetermination between regularly scheduled redeterminations. Sitio OpCo could also request one additional redetermination between regularly scheduled redeterminations and may request additional redeterminations as appropriate after significant acquisitions of oil and gas properties. The Sitio Borrowing Base is subject to adjustments for asset dispositions, material title deficiencies, certain terminations of hedge agreements and issuances of certain additional indebtedness. The Sitio Revolving Credit Facility is collateralized by substantially all of the assets of Sitio OpCo and its restricted subsidiaries.
The Sitio Revolving Credit Facility contains customary affirmative and negative covenants, including, without limitation, reporting obligations, restrictions on asset sales, restrictions on additional debt and lien incurrence and restrictions on making dividends or distributions, restrictions on paying other debt and restrictions on certain investments. The Sitio Credit Agreement requires us to maintain (a) a current ratio of not less than 1.00 to 1.00 and (b) a ratio of total net funded debt to consolidated EBITDA of not more than 3.50 to 1.00, with cash netting capped at $25.0 million for purposes of the calculation of total net funded debt. EBITDA for the period ending on December 31, 2024 is calculated as EBITDA for the period beginning on January 1, 2024 and ending on December 31, 2024, as adjusted for material acquisitions and dispositions completed during the reference period. The Company was in compliance with the terms and covenants of the Sitio Revolving Credit Facility at December 31, 2024 and 2023.
2028 Senior Notes
On October 3, 2023, Sitio OpCo and Sitio Finance Corp., a Delaware corporation, issued and sold $600.0 million aggregate principal amount of 7.875% Senior Notes due 2028. The 2028 Senior Notes were issued at par. Sitio OpCo used proceeds from the issuance of the 2028 Senior Notes to repay and redeem Sitio OpCo’s senior notes due 2026 (the “2026 Senior Notes”) in full, inclusive of a redemption premium of 3.0%. Remaining proceeds from the 2028 Senior Notes offering were used to repay outstanding borrowings under the Sitio Revolving Credit Facility and for general corporate purposes.
The 2028 Senior Notes are governed by the indenture, dated as of October 3, 2023 (the “Indenture”), by and among the Issuers, solely for purposes of Section 4.16(b) therein, the Company, the guarantors named therein and Citibank, N.A., as trustee (the “Trustee”). The 2028 Senior Notes are senior unsecured obligations of the Issuers, and are fully and unconditionally guaranteed on a senior unsecured basis by all of Sitio OpCo’s subsidiaries, other than Sitio Finance Corp. The 2028 Senior Notes will mature on November 1, 2028 and bear interest at an annual rate of 7.875%, which accrues
from October 3, 2023 and is payable semi-annually in arrears on May 1 and November 1 of each year, commencing on May 1, 2024.
At any time prior to November 1, 2025, the Issuers may, on any one or more occasions, redeem up to 35% of the aggregate principal amount of the 2028 Senior Notes (including any additional notes issued under the Indenture) at a redemption price equal to 107.875% of the principal amount of the 2028 Senior Notes redeemed, plus accrued and unpaid interest, if any, to, but excluding, the date of redemption, with an amount of cash not greater than the net cash proceeds of certain equity offerings, if at least 65% of the aggregate principal amount of the 2028 Senior Notes originally issued on the Issue Date (as defined in the Indenture) remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of such equity offering. At any time prior to November 1, 2025, the Issuers may, on any one or more occasions, redeem all or a part of the 2028 Senior Notes at a redemption price equal to 100% of the principal amount of the 2028 Senior Notes redeemed, plus the Applicable Premium (as defined in the Indenture) as of, and accrued and unpaid interest, if any, to, but excluding, the redemption date.
On or after November 1, 2025, the Issuers may, on any one or more occasions, redeem all or a part of the 2028 Senior Notes at the redemption prices (expressed as percentages of the principal amount) set forth below, plus accrued and unpaid interest, if any, to, but excluding the redemption date, if redeemed during the twelve-month period beginning on November 1 of the years indicated below:
Year
Percentage
2027 and thereafter
If Sitio OpCo experiences certain kinds of changes of control (and, in some cases, followed by a ratings decline), each holder of 2028 Senior Notes may have the right to require the Issuers to repurchase all or any part of such holder’s 2028 Senior Notes at 101% of the aggregate principal amount of the 2028 Senior Notes, plus accrued and unpaid interest, if any, to, but excluding, the date of repurchase.
The Indenture contains covenants that, among other things, limit Sitio OpCo’s ability and the ability of Sitio OpCo’s restricted subsidiaries to: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends on capital stock or redeem, repurchase or retire its capital stock or subordinated indebtedness; (iii) transfer or sell assets; (iv) make investments; (v) create certain liens; (vi) enter into agreements that restrict dividends or other payments from its restricted subsidiaries to it or any guarantor; (vii) consolidate, merge or transfer all or substantially all of its assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries.
If an Event of Default (as defined in the Indenture) occurs and is continuing under the Indenture, the Trustee or the holders of at least 25% in aggregate principal amount of the then total outstanding 2028 Senior Notes (with a copy to the Trustee) may declare the principal of, and accrued and unpaid interest, if any, on all outstanding 2028 Senior Notes to be due and payable immediately; provided that the 2028 Senior Notes will be due and payable immediately without further action or notice if such an Event of Default arises from certain events of bankruptcy or insolvency described in the Indenture with respect to the Issuers, any restricted subsidiary of Sitio OpCo that is a significant subsidiary or any group of restricted subsidiaries of Sitio OpCo that, taken together, would constitute a significant subsidiary.
As of December 31, 2024 and 2023, the Company had $600.0 million of 2028 Senior Notes outstanding. As of December 31, 2024 and 2023, the Company had unamortized debt issuance costs of $9.6 million and $11.7 million in connection with the issuance of the 2028 Senior Notes, respectively. Debt issuance costs are reported as a reduction to long-term debt on our consolidated balance sheets and are amortized over the life of the 2028 Senior Notes. For the year ended December 31, 2024 and 2023, the Company recognized $2.0 million and $474,000, respectively, of interest expense attributable to the amortization of debt issuance costs related to the 2028 Senior Notes. No such expense was recognized for the year ended December 31, 2022.
New and Revised Financial Accounting Standards
Refer to “Recent Accounting Pronouncements” in “Note 2 – Summary of Significant Accounting Policies” to our consolidated financial statements for the years ended December 31, 2024, 2023, and 2022 for a discussion of recent accounting pronouncements.
Contractual Obligations
As of December 31, 2024, we did not have any material capital lease obligations, operating lease obligations, debt, or long-term liabilities, other than borrowings under the Sitio Revolving Credit Facility, borrowings under the 2028 Senior Notes and operating lease agreements for office space. Please see “—Sitio Revolving Credit Facility” for a description of the Sitio Revolving Credit Facility, and “—2028 Senior Notes” for a description of the 2028 Senior Notes.
Critical Accounting Policies and Related Estimates
The discussion and analysis of financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. Our critical accounting policies are described below to provide a better understanding of how we develop our assumptions and judgments about future events and related estimates and how they can impact our financial statements. A critical accounting estimate is one that requires our most difficult, subjective or complex estimates and assessments and is fundamental to our results of operations.
We base our estimates on historical experience and on various other assumptions we believe to be reasonable according to the facts and circumstances at the time the estimates are made. Uncertainties with respect to such estimates and assumptions are inherent in the preparation of financial statements. There can be no assurance that actual results will not differ from those estimates and assumptions. This discussion and analysis should be read in conjunction with our consolidated financial statements and related notes.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. Changes in estimates are accounted for prospectively.
Our estimates and classification of oil and natural gas reserves are, by necessity, projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering, and geological interpretation and judgment. Estimates of economically recoverable oil and natural gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions. These factors and assumptions include historical production from the area compared with production from other producing areas, the assumed effect of regulations by governmental agencies, and assumptions governing future oil and natural gas prices. For these reasons, estimates of the economically recoverable quantities of expected oil and natural gas and estimates of the future net cash flows may vary substantially.
Any significant variance in the assumptions could materially affect the estimated quantity of reserves, which could affect the carrying value of our oil and natural gas properties and/or the rate of depletion related to oil and natural gas properties.
Oil and Gas Properties
We use the successful efforts method of accounting for oil and natural gas producing properties, as further defined under Accounting Standards Codification 932, Extractive Activities—Oil and Natural Gas . Under this method, costs to acquire mineral interests in oil and natural gas properties are capitalized. The costs of non-producing mineral interests and associated acquisition costs are capitalized as unproved properties pending the results of leasing efforts and drilling activities of E&P operators on our interests. As unproved properties are determined to have proved reserves, the related costs are transferred to proved oil and gas properties. Capitalized costs for proved oil and natural gas mineral interests are depleted on a unit-of-production basis over total proved reserves. For depletion of proved oil and gas properties, interests are grouped in a reasonable aggregation of properties with common geological structural features or stratigraphic conditions.
Impairment of Oil and Gas Properties
We evaluate our proved properties for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. When assessing proved properties for impairment, we compare the expected undiscounted future cash flows of the proved properties to the carrying amount of the proved properties to
determine recoverability. If the carrying amount of proved properties exceeds the expected undiscounted future net cash flows, the carrying amount is written down to the properties’ estimated fair value, which is measured as the present value of the expected future net cash flows of such properties. The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of future production, and a risk-adjusted discount rate. The proved property impairment test is primarily impacted by future commodity prices, changes in estimated reserve quantities, estimates of future production, overall proved property balances, and depletion expense. If pricing conditions decline or are depressed, or if there is a negative impact on one or more of the other components of the calculation, we may incur proved property impairments in future periods.
Unproved oil and gas properties are assessed periodically for impairment of value, and a loss is recognized at the time of impairment by charging capitalized costs to expense. Impairment is assessed based on when facts and circumstances indicate that the carrying value may not be recoverable, at which point an impairment loss is recognized to the extent the carrying value exceeds the estimated recoverable value. Factors used in the assessment include, but are not limited to, commodity price outlooks, current and future operator activity, and analysis of recent mineral transactions in the surrounding area.
Crude Oil, Natural Gas and NGLs Reserve Quantities and Standardized Measure of Oil and Gas
Our estimates of crude oil, natural gas and NGLs reserves and associated future net cash flows are prepared or audited by our independent reservoir engineers. The SEC has defined proved reserves as the estimated quantities of oil and gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The process of estimating crude oil, natural gas and NGLs reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material.
There are numerous uncertainties inherent in estimating quantities of proved crude oil, natural gas and NGLs reserves. Crude oil, natural gas and NGLs reserve engineering is a process of estimating underground accumulations of crude oil, natural gas and NGLs that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify positive or negative revisions of reserve estimates.
Revenue Recognition
Mineral and royalty interests represent the right to receive revenues from the sale of oil, natural gas and NGLs, less production taxes and post-production expenses. The prices of oil, natural gas, and NGLs from the properties in which we own a mineral or royalty interest are primarily determined by supply and demand in the marketplace and can fluctuate considerably. As an owner of mineral and royalty interests, we have no working interest or operational control over the volumes and methods of sale of the oil, natural gas, and NGL produced and sold from our properties. We do not explore, develop, or operate the properties and, accordingly, do not incur any of the associated costs. As we do not operate any of the wells for which we receive royalties, we have limited visibility into the timing of when new wells start producing and production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, we are required to estimate the amount of production delivered to the purchaser and the price that we will receive for the sale of the product. The expected sales volumes and prices for these properties are estimated and recorded within the Accrued revenue and accounts receivable line item in the accompanying consolidated balance sheets. Differences between our estimates and the actual amounts received for oil and natural gas sales are recorded in the month that payment is received from the third party.
Oil, natural gas, and NGLs revenues from our mineral and royalty interests are recognized when control transfers at the wellhead.
We also earn revenue related to lease bonuses by leasing our mineral interests to E&P companies. We recognize lease bonus revenue when the lease agreement has been executed and payment is determined to be collectible.
