Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion and analysis should be read in conjunction with the audited consolidated financial statements and notes thereto for the years ended December 31, 2021, 2020, and 2019 of Kimmeridge Mineral Fund, L.P. in the Current Report on Form 8-K filed with the SEC on June 10, 2022 and interim unaudited condensed consolidated financial statements of Sitio Royalties Corp. and notes thereto included elsewhere in this Quarterly Report on Form 10-Q. Except as otherwise indicated or required by context, references to (a) the “Company,” “Sitio,” “we,” “us,” “our” or similar terms refer to (i) for periods prior to the closing of the Falcon Merger, Desert Peak and its subsidiaries and (ii) for periods subsequent to the closing of the Falcon Merger, Sitio Royalties Corp. and its subsidiaries, including Desert Peak and (b) “KMF,” “KMF Land,” “Desert Peak,” or similar terms, when used in a historical context refer to our “Predecessor,” Kimmeridge Mineral Fund, LP, for financial reporting purposes.
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 “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 September 30, 2022, we owned mineral and royalty interests representing approximately 174,000 NRAs when adjusted to a 1/8th royalty. For the three months ended September 30, 2022, the average net daily production associated with our mineral and royalty interest was 17,990 BOE/d, consisting of 9,192 Bbls/d of oil, 31,694 Mcf/d of natural gas and 3,515 Bbls/d of NGLs. For the nine months ended September 30, 2022, the average net daily production associated with our mineral and royalty interests was 13,950 BOE/d, consisting of 7,211 Bbls/d of oil, 23,741 Mcf/d of natural gas and 2,782 Bbls/d of NGLs. Since our Predecessor’s formation in November 2016, we have accumulated our acreage position by making 185 acquisitions. 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 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 nine months ended September 30, 2022, our production and ad valorem taxes were approximately $4.73 per BOE, relative to an average realized price of $68.33 per BOE. We do not anticipate engaging in any activities, other than acquisitions, that will incur capital 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
Brigham Merger
On September 6, 2022, Sitio, Sitio OpCo, New Sitio, Brigham Merger Sub, Sitio Merger Sub, and Opco Merger Sub LLC entered into the Merger Agreement with Brigham and Brigham Opco, pursuant to which, Sitio will acquire Brigham in an all-stock transaction through: (i) the Brigham Subsidiary Merger, with Brigham surviving the Brigham Subsidiary Merger as a wholly owned subsidiary of New Sitio, (ii) the Sitio Merger, with Sitio surviving the Sitio Merger as a wholly owned subsidiary of New Sitio, and (iii) the Opco Merger , with Brigham Opco surviving the Opco Merger as a wholly owned subsidiary of Sitio OpCo, in each case on the terms set forth in the Merger Agreement. The Sitio Merger and the Brigham Subsidiary Merger shall become effective concurrently at the First Effective Time, and the Opco Merger shall become effective immediately following the First Effective Time at the Second Effective Time.
On the terms and subject to the conditions set forth in the Merger Agreement, (i) at the First Effective Time, (A) each share of Brigham’s Class A common stock, par value $0.01 per share, issued and outstanding immediately prior to the First Effective Time will be converted into the right to receive 1.133 fully-paid and nonassessable shares of New Sitio Class A Common Stock, (B) each share of the Brigham’s Class B common stock, par value $0.01 per share, issued and outstanding immediately prior to the First Effective Time will be converted into the right to receive 1.133 fully-paid and nonassessable shares of New Sitio Class C Common Stock, (C) each share of Class A Common Stock, issued and outstanding immediately prior to the First Effective Time will be converted into one share of New Sitio Class A Common Stock and (D) each share of Class C Common Stock issued and outstanding immediately prior to the First Effective Time, will be converted into one share of New Sitio Class C Common Stock, in each case, excluding shares owned by
37
Sitio, Brigham or any wholly owned subsidiary of Sitio or Brigham and, to the extent applicable, shares owned by stockholders who have perfected and not withdrawn a demand for appraisal rights pursuant to the DGCL and, (ii) at the Second Effective Time, each Brigham Opco Unit issued and outstanding immediately prior to the Second Effective Time will be converted into the right to receive 1.133 Sitio OpCo Partnership Units.
As a result of the Brigham Merger and as of the Closing, Sitio stockholders immediately prior to the First Effective Time will own approximately 54% of the outstanding shares of New Sitio, and Brigham stockholders immediately prior to the First Effective Time will own approximately 46% of the outstanding shares of New Sitio. Following the Closing, New Sitio will operate under the name “Sitio Royalties Corp.”
Credit Facility
On September 21, 2022, Sitio OpCo and the other guarantors party thereto entered into the RBL Third Amendment, pursuant to which the Revolving Credit Facility was amended to permit the issuance of notes and the transactions contemplated by the Note Purchase Agreement.
2026 Senior Notes
On September 21, 2022, Sitio OpCo, as issuer, and certain subsidiaries of Sitio OpCo, as guarantors, entered into the Note Purchase Agreement with the Holders.
Pursuant to the Note Purchase Agreement, Sitio OpCo issued the 2026 Senior Notes to the Holders in an aggregate principal amount of $450.0 million. Sitio OpCo used $425.0 million of the proceeds from the 2026 Senior Notes to repay in full all amounts outstanding under the Bridge Loan Facility with the remainder used for general corporate purposes. The 2026 Senior Notes mature on September 21, 2026.
Sitio OpCo may elect, at its option, to prepay the 2026 Senior Notes in whole or in part at any time, subject to payment of a premium determined in accordance with the table below based on the length of time between the issuance date and the prepayment date:
|
|
|
|
|
Period |
|
Premium |
|
Months 0 - 12 |
|
Customary “make-whole” premium plus 3.00% |
|
Months 13 - 24 |
|
|
3.00 |
% |
Months 25 - 36 |
|
|
1.00 |
% |
Months 37 - 48 |
|
|
0.00 |
% |
364-Day Bridge Loan Agreement
On June 24, 2022, Sitio OpCo, a wholly owned subsidiary of Sitio Royalties Corp, as borrower, entered into the Bridge Loan Agreement with Bank of America, N.A. as Administrative Agent for the Lenders, BofA Securities, Inc., as joint lead arranger and sole bookrunner, and Barclays Bank PLC and KeyBank National Association, as joint lead arrangers. The Bridge Loan Agreement provides for a 364-day term loan credit facility in the aggregate principal amount of $425.0 million. The Bridge Loan Facility was fully repaid and extinguished on September 21, 2022 using proceeds from the issuance of the 2026 Senior Notes. Upon closure of the Bridge Loan Facility, the Company recognized a loss on extinguishment of debt of $11.5 million associated with unamortized debt issuance costs and other fees incurred in connection with the payoff.
Acquisitions
As of September 30, 2022, we have evaluated over 1,000 potential mineral and royalty interest acquisitions and completed 185 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.
On July 26, 2022, the Company acquired approximately 12,200 net royalty acres from Momentum for a purchase price of $213.3 million, net of customary closing adjustments. The Momentum Acquisition was funded through the Bridge Loan Facility and the Revolving Credit Facility, in addition to cash on hand.
Production and Operations
Our average daily production during the three months ended September 30, 2022 and 2021 was 17,990 BOE/d (51% crude oil) and 7,810 BOE/d (51% crude oil), respectively. For the three months ended September 30, 2022, we received an average of $93.81 per Bbl of crude oil, $6.55 per Mcf of natural gas and $31.98 per Bbl of NGLs, for an average realized price of $65.71 per BOE. For the three months ended September 30, 2021, we received an average of $66.61 per Bbl of crude oil, $3.74 per Mcf of natural gas and $29.43 per Bbl of NGLs, for an average realized price of $46.14 per BOE.
38
Our average daily production during the nine months ended September 30, 2022 and 2021 was 13,950 BOE/d (52% crude oil) and 6,012 BOE/d (48% crude oil), respectively. For the nine months ended September 30, 2022, we received an average of $98.12 per Bbl of crude oil, $6.05 per Mcf of natural gas and $36.68 per Bbl of NGLs, for an average realized price of $68.33 per BOE. For the nine months ended September 30, 2021, we received an average of $62.63 per Bbl of crude oil, $3.43 per Mcf of natural gas and $28.31 per Bbl of NGLs, for an average realized price of $42.11 per BOE.
As of September 30, 2022, we had 15,933 gross (127.4 net) producing horizontal wells on our acreage. Additionally, as of September 30, 2022, there were 3,002 gross (15.9 net) horizontal wells in various stages of drilling or completion and 2,417 gross active horizontal drilling permits on our acreage.
Economic Indicators
The economy is experiencing elevated inflation levels as a result of global supply and demand imbalances, where global demand continues to outpace current supplies. The BLS Consumer Price Index for all urban consumers increased 8% from September 2021 to September 2022 as compared to the average annual increase of 3% over the previous 10 years. In order to manage the inflation risk currently present in the United States’ economy, the Federal Reserve has utilized monetary policy in the form of interest rate increases in an effort to bring the inflation rate in line with its stated goal of 2% on a long-term basis.
The global economy also continues to be impacted by the effects of the COVID-19 pandemic and global events, among other factors. These events have often caused global supply chain disruptions with additional pressure due to trade sanctions on Russia and other global trade restrictions, among others. As we do not explore, develop or operate on our oil and gas properties, we have not experienced any significant supply chain interruptions as a result of the COVID-19 pandemic or global supply and demand imbalances. However, our operators may experience supply chain disruptions which could impact their ability to develop our properties.
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 resulting 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.
COVID-19 Pandemic
The initial outbreak of COVID-19 caused a disruption to the oil and natural gas industry and to our business by, among other things, contributing to a significant decrease in global crude oil demand and the price for oil in 2020. This disruption was somewhat alleviated in 2021 and 2022, with the increase in domestic vaccination programs and reduced spread of the COVID-19 virus contributing to an improvement in the economy and higher realized prices for commodities. Since mid-2020 through mid-2022, oil prices have generally improved, with demand steadily increasing despite the uncertainties surrounding the COVID-19 variants, which have continued to inhibit a full global demand recovery. However, the current price environment remains uncertain as responses to the COVID-19 pandemic and newly emerging variants of the virus continue to evolve. Many operators have resumed or increased drilling and completion activities compared to activity levels in 2020 in connection with the increase in commodity prices since mid-2020. Given the dynamic nature of these events, the Company cannot reasonably estimate the period of time that the COVID-19 pandemic and related market conditions will persist and the impacts on our business from the COVID-19 pandemic, efforts to fight the pandemic and other market events.
The impact of recent developments in Ukraine
In February 2022, Russia launched a large-scale invasion of Ukraine that has led to significant armed hostilities. As a result, the United States, the United Kingdom, the member states of the European Union and other public and private actors have levied severe sanctions on Russian financial institutions, businesses and individuals. This conflict, and the resulting sanctions, has contributed to significant increases and volatility in the price for oil and natural gas, with the posted price for WTI reaching a high of $123.64 per barrel in March 2022. This volatility could negatively impact commodity prices and cause rising inflation that could impact demand for refined products. Given the uncertain timing of a return of refined product demand to historical levels, the extent these events will have an impact on our results of operations is unclear. The geopolitical and macroeconomic consequences of this invasion and associated sanctions cannot be predicted, and such events, or any further hostilities in Ukraine or elsewhere, could severely impact the world economy and may adversely affect our financial condition. The Russian conflict with Ukraine continues 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.
39
Regulatory Update
Proposed SEC Climate Disclosure Rules
On March 21, 2022, the U.S. Securities and Exchange Commission proposed new rules relating to the disclosure of a range of climate-related risks. We are currently assessing the rule, but at this time we cannot predict the costs of implementation or any potential adverse impacts resulting from the rule. To the extent this rule is finalized as proposed, we or our operators could incur increased costs relating to the assessment and disclosure of climate-related risks. We may also face increased litigation risks related to disclosures made pursuant to the rule if finalized as proposed. In addition, enhanced climate disclosure requirements could accelerate the trend of certain stakeholders and lenders restricting or seeking more stringent conditions with respect to their investments in certain carbon-intensive sectors.
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;
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 $1.33 per MMBtu in September 2020 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 Btus 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
40
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 a limited global transportation system, 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.
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 without regard to financing methods, capital structure or historical cost basis.
We define Adjusted EBITDA as net income (loss) plus (a) interest expense, (b) provisions for taxes, (c) depreciation, depletion and amortization, (d) non-cash share-based compensation expense, (e) impairment of oil and natural gas properties, (f) gains or losses on unsettled derivative instruments, (g) change in fair value of warrant liability, (h) write off of deferred offering costs, (i) management fee to affiliates, (j) loss on extinguishment of debt (k) one-time transaction costs and (l) write off of financing costs. 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.
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 nine months ended September 30, 2022 and 2021, mineral and royalty revenue made up 96% and 98%, respectively, of our total revenue. 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
|
2022 |
|
|
2021 |
|
|
2022 |
|
|
2021 |
|
|
Crude oil sales |
|
|
69 |
% |
|
|
72 |
% |
|
|
72 |
% |
|
|
70 |
% |
|
Natural gas sales |
|
|
17 |
% |
|
|
14 |
% |
|
|
15 |
% |
|
|
16 |
% |
|
NGL sales |
|
|
8 |
% |
|
|
12 |
% |
|
|
9 |
% |
|
|
12 |
% |
|
Lease bonus and other income |
|
|
6 |
% |
|
|
2 |
% |
|
|
4 |
% |
|
|
2 |
% |
|
Total revenues |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
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 and natural gas based on a percentage of revenues from 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
41
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.
Gathering, Processing and Transportation Costs
Gathering, processing and transportation costs are representative of the costs to process and transport our respective volumes to applicable sales points. The terms of the lease with the applicable E&P operator on our interests determines if the operator is able to pass through these costs to us by deducting a pro rata portion of such costs from our production revenues.
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. 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 our 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, tax return preparation expenses, Sarbanes-Oxley Act compliance expenses, expenses associated with listing our common stock, independent auditor fees, 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 finance a portion of our working capital requirements and acquisitions with borrowings under our Revolving Credit Facility and 2026 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 Facility and 2026 Senior Notes and amortization of debt issuance costs in interest expense on our statements of income.
Income Tax Expense
As a result of the Falcon Merger, we are subject to U.S. federal and state taxes as a corporation. 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.
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 do 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, a Director, is a managing member. Fees incurred under the
42
agreement totaled approximately $3.2 million and $5.6 million for the nine months ended September 30, 2022 and 2021, respectively. We will not incur future expense under the agreement as a result of the Falcon Merger. Additionally, certain other expenses associated with the limited partnership structure of the Predecessor will not be incurred by us in future periods.
Acquisitions
Our Predecessor’s financial statements as of and for the nine months ended September 30, 2021 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, and Momentum 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 our 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
As a result of the Falcon Merger, we incur incremental general and administrative expenses as a result of Kimmeridge no longer providing services to us and 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 common stock, independent auditor fees, independent reserve engineer fees, 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, 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 will continue to be subject as a corporation.
43
Results of Operations
Three Months Ended September 30, 2022 Compared to the Three Months Ended September 30, 2021
Consolidated Results
The following table summarizes our consolidated revenue and expenses and production data for the three months ended September 30, 2022 and 2021 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
September 30, |
|
|
|
2022 |
|
|
2021 |
|
Statement of Income Data: |
|
|
|
|
|
|
Revenue: |
|
|
|
|
|
|
Total Revenue |
|
$ |
115,497 |
|
|
$ |
33,709 |
|
Operating Expenses: |
|
|
|
|
|
|
Management fees to affiliates |
|
|
— |
|
|
|
1,870 |
|
Depreciation, depletion and amortization |
|
|
32,005 |
|
|
|
12,813 |
|
General and administrative |
|
|
13,381 |
|
|
|
954 |
|
General and administrative—affiliates |
|
|
— |
|
|
|
1,686 |
|
Severance and ad valorem taxes |
|
|
7,215 |
|
|
|
2,192 |
|
Total operating expenses |
|
|
52,601 |
|
|
|
19,515 |
|
Net income from operations |
|
|
62,896 |
|
|
|
14,194 |
|
Interest expense (net)(1) |
|
|
(14,986 |
) |
|
|
(276 |
) |
Change in fair value of warrant liability |
|
|
536 |
|
|
|
— |
|
Loss on extinguishment of debt |
|
|
(11,487 |
) |
|
|
— |
|
Commodity derivatives gains |
|
|
34,613 |
|
|
|
— |
|
Net income before income tax expense |
|
|
71,572 |
|
|
|
13,918 |
|
Income tax expense |
|
|
(2,561 |
) |
|
|
(143 |
) |
Net income |
|
|
69,011 |
|
|
|
13,775 |
|
Net income attributable to Predecessor |
|
|
— |
|
|
|
(13,775 |
) |
Net income attributable to temporary equity |
|
|
(59,872 |
) |
|
|
— |
|
Net income attributable to Class A stockholders |
|
$ |
9,139 |
|
|
$ |
— |
|
(1)Interest expense is presented net of interest income.
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
September 30, |
|
|
|
2022 |
|
|
2021 |
|
Production Data: |
|
|
|
|
|
|
Crude oil (MBbls) |
|
|
846 |
|
|
|
363 |
|
Natural gas (Mmcf) |
|
|
2,916 |
|
|
|
1,290 |
|
NGLs (MBbls) |
|
|
323 |
|
|
|
140 |
|
Total (MBOE)(6:1) |
|
|
1,655 |
|
|
|
718 |
|
Average daily production (BOE/d)(6:1) |
|
|
17,990 |
|
|
|
7,810 |
|
Average Realized Prices: |
|
|
|
|
|
|
Crude oil (per Bbl) |
|
$ |
93.81 |
|
|
$ |
66.61 |
|
Natural gas (per Mcf) |
|
$ |
6.55 |
|
|
$ |
3.74 |
|
NGLs (per Bbl) |
|
$ |
31.98 |
|
|
$ |
29.43 |
|
Combined (per BOE) |
|
$ |
65.71 |
|
|
$ |
46.14 |
|
Average Realized Prices After Effects of Derivative Settlements: |
|
|
|
|
|
|
Crude oil (per Bbl) |
|
$ |
97.32 |
|
|
$ |
66.61 |
|
Natural gas (per Mcf) |
|
$ |
6.46 |
|
|
$ |
3.74 |
|
NGLs (per Bbl) |
|
$ |
31.98 |
|
|
$ |
29.43 |
|
Combined (per BOE) |
|
$ |
67.36 |
|
|
$ |
46.14 |
|
44
Revenue
Our consolidated revenues for the three months ended September 30, 2022 totaled $115.5 million as compared to $33.7 million for the three months ended September 30, 2021, an increase of 243%. The increase in revenues was due to an increase of $75.6 million in mineral and royalty revenue and an increase of $6.2 million in lease bonus and other income. The increase in mineral and royalty revenue was primarily due to increased commodity prices, production volumes from our acquisitions of additional mineral and royalty interests, and production volumes from existing interests. Lease bonus and other income is subject to significant variability from period to period based on the particular tracts of land that become available for releasing.
Oil revenue for the three months ended September 30, 2022 was $79.3 million as compared to $24.2 million for the three months ended September 30, 2021, an increase of $55.1 million. An increase of $27.20/Bbl in our average price received for oil production, from $66.61/Bbl for the three months ended September 30, 2021 to $93.81/Bbl for the three months ended September 30, 2022, accounted for an approximate $23.0 million increase in our year-over-year oil revenue. Additionally, we realized a $32.1 million increase in year-over-year oil revenue due to a 133% increase in oil production volumes, which increased from 363 MBbls for the three months ended September 30, 2021 to 846 MBbls for the three months ended September 30, 2022.
Natural gas revenue for the three months ended September 30, 2022 was $19.1 million as compared to $4.8 million for the three months ended September 30, 2021, an increase of $14.3 million. An increase of $2.81/Mcf in our average price received for gas production, from $3.74/Mcf for the three months ended September 30, 2021 to $6.55/Mcf for the three months ended September 30, 2022, accounted for an approximate $8.2 million increase in our year-over-year gas revenue. Additionally, we realized a $6.1 million increase in year-over-year gas revenue due to a 126% increase in gas production volumes, which increased from 1,290 MMcf for the three months ended September 30, 2021 to 2,916 MMcf for the three months ended September 30, 2022.
NGLs revenue for the three months ended September 30, 2022 was $10.3 million as compared to $4.1 million for the three months ended September 30, 2021, an increase of $6.2 million. An increase of $2.55/Bbl in our average price received for NGLs production, from $29.43/Bbl for the three months ended September 30, 2021 to $31.98/Bbl for the three months ended September 30, 2022, accounted for an approximate $825,000 increase in our year-over-year NGLs revenue. Additionally, we realized a $5.4 million increase in year-over-year NGLs revenue due to a 131% increase in NGLs production volumes, which increased from 140 MBbls for the three months ended September 30, 2021 to 323 MBbls for the three months ended September 30, 2022.
Lease bonus revenue for the three months ended September 30, 2022 was $6.5 million as compared to $487,000 for the three months ended September 30, 2021. 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 for the three months ended September 30, 2022 were $253,000 as compared to $70,000 for the three months ended September 30, 2021, which include payments for right-of-way and surface damages, which are also subject to significant variability.
Operating Expenses
The Predecessor entered into a management services arrangement with Kimmeridge Energy Management Company, LLC. Management fees to the Predecessor’s affiliates expense was $1.9 million for the three months ended September 30, 2021, respectively. No such expense was incurred for the three months ended September 30, 2022. The decrease of $1.9 million was due to the Falcon Merger as the Company no longer incurs any management fees.
Depreciation, depletion and amortization expense was $32.0 million for the three months ended September 30, 2022 as compared to $12.8 million for the three months ended September 30, 2021, an increase of $19.2 million, or 150%. The increase was due to a 130% increase in year-over-year production and a higher depletion rate, which increased from $17.63 per BOE for the three months ended September 30, 2021 to $19.24 per BOE for the three months ended September 30, 2022.
General and administrative expense was $13.4 million for the three months ended September 30, 2022 as compared to $954,000 for the three months ended September 30, 2021, an increase of $12.4 million. The increase was primarily due to increased personnel costs due to increased headcount for the three months ended September 30, 2022, public transaction costs related to the Falcon Merger and Brigham Merger, and expenses as a result of operating as a publicly traded company.
General and administrative—affiliates expense was $1.7 million for the three months ended September 30, 2021. We did not incur any General and administrative—affiliates expense for the three months ended September 30, 2022. The decrease was primarily a result of decreased reimbursement to our Predecessor’s general partner for services provided on our behalf, including personnel costs and costs relating to the performance of land and administrative services in respect of our acquisition of mineral and royalty interests. These costs were captured in the General and administrative expense line item for the three months ended September 30, 2022.
On a combined basis, the General and administrative expense and General and administrative expense—affiliates expense was $13.4 million for the three months ended September 30, 2022 as compared to $2.6 million for the three months ended September 30,
45
2021, an increase of $10.8 million, or 407%, primarily due to $4.0 million of share-based compensation expense, $3.6 million of transaction costs related to the Falcon Merger and Brigham Merger, $0.5 million of additional employee compensation due to increased headcount, and $2.7 million of additional other professional services.
Severance and ad valorem taxes were $7.2 million for the three months ended September 30, 2022 as compared to $2.2 million for the three months ended September 30, 2021, an increase of $5.0 million or 229%. The increase was primarily due to the year-over-year increase in commodity prices and increased production volumes from our acquisitions of additional mineral and royalty interests and existing interests.
Interest expense of approximately $15.0 million and $276,000 during the three months ended September 30, 2022 and 2021, respectively, relates to interest incurred on borrowings under our Revolving Credit Facility, 2026 Senior Notes and Bridge Loan Facility. The increase in interest expense was due to higher average borrowings during the three months ended September 30, 2022 as compared to the three months ended September 30, 2021 related to funding the Falcon Merger and other acquisitions in 2022.
The fair value of the warrant liability decreased by $536,000 during the three months ended September 30, 2022, whereas there were no changes to the fair value of the warrant liability for the three months ended September 30, 2021. The change is attributable to a decrease in the market price of both the Public Warrants and Private Placement Warrants.
Commodity derivatives gains totaled $34.6 million for the three months ended September 30, 2022, whereas there were no derivatives gains or losses for the three months ended September 30, 2021. In 2022, we entered into oil and gas fixed price swaps and two-way collars to manage commodity price risks associated with production from our recent acquisitions.
Income tax expense increased from $143,000 for the three months ended September 30, 2021 to $2.6 million for the three months ended September 30, 2022. The increase was primarily due to current and deferred income taxes due to our classification as a taxable corporation subsequent to the Falcon Merger, whereas the Predecessor was not subject to Federal income taxes during the three months ended September 30, 2021.
Nine Months Ended September 30, 2022 Compared to the Nine Months Ended September 30, 2021
Consolidated Results
The following table summarizes our consolidated revenue and expenses and production data for the nine months ended September 30, 2022 and 2021 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
September 30, |
|
|
|
2022 |
|
|
2021 |
|
Statement of Income Data: |
|
|
|
|
|
|
Revenue: |
|
|
|
|
|
|
Total Revenue |
|
$ |
269,664 |
|
|
$ |
70,428 |
|
Operating Expenses: |
|
|
|
|
|
|
Management fees to affiliates |
|
|
3,241 |
|
|
|
5,610 |
|
Depreciation, depletion and amortization |
|
|
67,302 |
|
|
|
28,614 |
|
General and administrative |
|
|
24,043 |
|
|
|
2,232 |
|
General and administrative—affiliates |
|
|
74 |
|
|
|
4,903 |
|
Severance and ad valorem taxes |
|
|
18,019 |
|
|
|
4,766 |
|
Total operating expenses |
|
|
112,679 |
|
|
|
46,125 |
|
Net income from operations |
|
|
156,985 |
|
|
|
24,303 |
|
Interest expense (net)(1) |
|
|
(18,096 |
) |
|
|
(800 |
) |
Change in fair value of warrant liability |
|
|
3,842 |
|
|
|
— |
|
Loss on extinguishment of debt |
|
|
(11,487 |
) |
|
|
— |
|
Commodity derivatives gains |
|
|
53,508 |
|
|
|
— |
|
Net income before income tax expense |
|
|
184,752 |
|
|
|
23,503 |
|
Income tax expense |
|
|
(5,206 |
) |
|
|
(233 |
) |
Net income |
|
|
179,546 |
|
|
|
23,270 |
|
Net income attributable to Predecessor |
|
|
(78,104 |
) |
|
|
(23,270 |
) |
Net income attributable to temporary equity |
|
|
(86,143 |
) |
|
|
— |
|
Net income attributable to Class A stockholders |
|
$ |
15,299 |
|
|
$ |
— |
|
(1)Interest expense is presented net of interest income.
46
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
September 30, |
|
|
|
2022 |
|
|
2021 |
|
Production Data: |
|
|
|
|
|
|
Crude oil (MBbls) |
|
|
1,969 |
|
|
|
783 |
|
Natural gas (Mmcf) |
|
|
6,481 |
|
|
|
3,244 |
|
NGLs (MBbls) |
|
|
760 |
|
|
|
320 |
|
Total (MBOE)(6:1) |
|
|
3,809 |
|
|
|
1,644 |
|
Average daily production (BOE/d)(6:1) |
|
|
13,950 |
|
|
|
6,021 |
|
Average Realized Prices: |
|
|
|
|
|
|
Crude oil (per Bbl) |
|
$ |
98.12 |
|
|
$ |
62.63 |
|
Natural gas (per Mcf) |
|
$ |
6.05 |
|
|
$ |
3.43 |
|
NGLs (per Bbl) |
|
$ |
36.68 |
|
|
$ |
28.31 |
|
Combined (per BOE) |
|
$ |
68.33 |
|
|
$ |
42.11 |
|
Average Realized Prices After Effects of Derivative Settlements: |
|
|
|
|
|
|
Crude oil (per Bbl) |
|
$ |
99.48 |
|
|
$ |
62.63 |
|
Natural gas (per Mcf) |
|
$ |
5.99 |
|
|
$ |
3.43 |
|
NGLs (per Bbl) |
|
$ |
36.68 |
|
|
$ |
28.31 |
|
Combined (per BOE) |
|
$ |
68.93 |
|
|
$ |
42.11 |
|
Revenue
Our consolidated revenues for the nine months ended September 30, 2022 totaled $269.7 million as compared to $70.4 million for the nine months ended September 30, 2021, an increase of 283%. The increase in revenues was due to an increase of $191.0 million in mineral and royalty revenue and an increase of $8.3 million in lease bonus and other income. The increase in mineral and royalty revenue was primarily due to increased commodity prices, production volumes from our acquisitions of additional mineral and royalty interests, and production volumes from existing interests. Lease bonus and other income is subject to significant variability from period to period based on the particular tracts of land that become available for releasing.
Oil revenue for the nine months ended September 30, 2022 was $193.2 million as compared to $49.0 million for the nine months ended September 30, 2021, an increase of $144.2 million. An increase of $35.49/Bbl in our average price received for oil production, from $62.63/Bbl for the nine months ended September 30, 2021 to $98.12/Bbl for the nine months ended September 30, 2022, accounted for an approximate $69.9 million increase in our year-over-year oil revenue. Additionally, we realized a $74.3 million increase in year-over-year oil revenue due to a 151% increase in oil production volumes, which increased from 783 MBbls for the nine months ended September 30, 2021 to 1,969 MBbls for the nine months ended September 30, 2022.
Natural gas revenue for the nine months ended September 30, 2022 was $39.2 million as compared to $11.1 million for the nine months ended September 30, 2021, an increase of $28.1 million. An increase of $2.62/Mcf in our average price received for gas production, from $3.43/Mcf for the nine months ended September 30, 2021 to $6.05/Mcf for the nine months ended September 30, 2022, accounted for an approximate $17.0 million increase in our year-over-year gas revenue. Additionally, we realized an $11.1 million increase in year-over-year gas revenue due to a 100% increase in gas production volumes, which increased from 3,244 MMcf for the nine months ended September 30, 2021 to 6,481 MMcf for the nine months ended September 30, 2022.
NGLs revenue for the nine months ended September 30, 2022 was $27.9 million as compared to $9.1 million for the nine months ended September 30, 2021, an increase of $18.8 million. An increase of $8.37/Bbl in our average price received for NGLs production, from $28.31/Bbl for the nine months ended September 30, 2021 to $36.68/Bbl for the nine months ended September 30, 2022, accounted for an approximate $6.4 million increase in our year-over-year NGLs revenue. Additionally, we realized a $12.4 million increase in year-over-year NGLs revenue due to a 137% increase in NGLs production volumes, which increased from 320 MBbls for the nine months ended September 30, 2021 to 760 MBbls for the nine months ended September 30, 2022.
Lease bonus revenue for the nine months ended September 30, 2022 was $8.5 million as compared to $574,000 for the nine months ended September 30, 2021. 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 for the nine months ended September 30, 2022 were $985,000 as compared to $633,000 for the nine months ended September 30, 2021, which include payments for right-of-way and surface damages, which are also subject to significant variability.
47
Operating Expenses
The Predecessor entered into a management services arrangement with Kimmeridge Energy Management Company, LLC. Management fees to the Predecessor’s affiliates expense was $3.2 million and $5.6 million for the nine months ended September 30, 2022 and 2021, respectively. The decrease of $2.4 million was due to the Falcon Merger as the Company will no longer incur any management fees.
Depreciation, depletion and amortization expense was $67.3 million for the nine months ended September 30, 2022 as compared to $28.6 million for the nine months ended September 30, 2021, an increase of $38.7 million, or 135%. The increase was due to a 132% increase in year-over-year production as well as a higher depletion rate, which increased from $17.14 per BOE for the nine months ended September 30, 2021 to $17.54 per BOE for the nine months ended September 30, 2022.
General and administrative expense was $24.0 million for the nine months ended September 30, 2022 as compared to $2.2 million for the nine months ended September 30, 2021, an increase of $21.8 million. The increase was primarily due to increased personnel costs captured here for the nine months ended September 30, 2022, public transaction costs related to the Falcon and Brigham Merger, and expenses as a result of operating as a publicly traded company.
General and administrative—affiliates expense was $74,000 for the nine months ended September 30, 2022 as compared to $4.9 million for the nine months ended September 30, 2021, a decrease of $4.8 million. The decrease was primarily a result of decreased reimbursement to our Predecessor’s general partner for services provided on our behalf, including personnel costs and costs relating to the performance of land and administrative services in respect of our acquisition of mineral and royalty interests. These costs were primarily captured in the General and administrative expense line item for the nine months ended September 30, 2022.
On a combined basis, the General and administrative expense and General and administrative expense—affiliates expense was $24.1 million for the nine months ended September 30, 2022 as compared to $7.1 million for the nine months ended September 30, 2021, an increase of $17.0 million, or 238%, primarily due to $6.8 million of transaction costs related to the Falcon Merger and Brigham Merger, $4.9 million of share-based compensation, $1.2 million of additional employee compensation due to increased headcount, $3.8 million of additional other professional services, and $0.3 million of additional rent expense.
Severance and ad valorem taxes were $18.0 million for the nine months ended September 30, 2022 as compared to $4.7 million for the nine months ended September 30, 2021, an increase of $13.3 million or 278%. The increase was primarily due to the year-over-year increase in commodity prices and increased production volumes from our acquisitions of additional mineral and royalty interests and existing interests.
Interest expense of approximately $18.1 million and $800,000 during the nine months ended September 30, 2022 and 2021, respectively, relates to interest incurred on borrowings under our Revolving Credit Facility, 2026 Senior Notes and Bridge Loan Facility. The increase in interest expense was due to higher average borrowings during the nine months ended September 30, 2022 as compared to nine months ended September 30, 2021 related to funding the Falcon Merger and other acquisitions in the nine months ended September 30, 2022.
The fair value of the warrant liability decreased by $3.8 million from the date of the Falcon Merger through September 30, 2022, whereas there were no changes to the fair value of the warrant liability for the nine months ended September 30, 2021. The change is attributable to a decrease in the market price of both the Public Warrants and Private Placement Warrants.
Commodity derivative gains totaled $53.5 million for the nine months ended September 30, 2022, whereas there were no derivatives gains or losses for the nine months ended September 30, 2021. In 2022, we entered into oil and gas fixed price swaps and two-way collars to manage commodity price risks associated with production from our recent acquisitions.
Income tax expense increased from $233,000 for the nine months ended September 30, 2021 to $5.2 million for the nine months ended September 30, 2022. The increase was primarily due to current and deferred income taxes due to our classification as a taxable corporation subsequent to the Falcon Merger, whereas the Predecessor was not subject to Federal income taxes during the nine months ended September 30, 2021.
Liquidity and Capital Resources
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 our Revolving Credit Facility and 2026 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
48
and royalty interests, the reduction of outstanding debt balances and the payment of dividends. 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 our 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 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, 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 unable to obtain funds needed or on acceptable terms, we may not be able to complete acquisitions that are favorable to us.
As of September 30, 2022, our liquidity was $83.8 million, comprised of $10.8 million of cash and cash equivalents and $73.0 million of Revolving Credit Facility availability.
Cash Flows Nine Months Ended September 30, 2022 Compared to the Nine Months Ended September 30, 2021 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
For the Nine Months Ended September 30, |
|
|
|
2022 |
|
|
2021 |
|
Statement of Cash Flows Data: |
|
|
|
|
|
|
Net cash provided by (used in): |
|
|
|
|
|
|
Operating activities |
|
$ |
171,075 |
|
|
$ |
40,563 |
|
Investing activities |
|
|
(569,626 |
) |
|
|
(26,937 |
) |
Financing activities |
|
|
396,984 |
|
|
|
(12,507 |
) |
Net increase (decrease) in cash and cash equivalents |
|
$ |
(1,567 |
) |
|
$ |
1,119 |
|
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 nine months ended September 30, 2022 were $171.1 million as compared to $40.6 million for the nine months ended September 30, 2021, primarily as a result of increases in realized prices and production volumes from our royalty revenue.
Investing Activities
Cash flows used in investing activities totaled $569.6 million for the nine months ended September 30, 2022 as compared $26.9 million for the nine months ended September 30, 2021, an increase of $542.7 million. Our expenditures for purchases of oil and gas properties increased by $531.2 million due to several cash acquisitions completed during the nine months ended September 30, 2022. During the nine months ended September 30, 2022, we purchased other property and equipment for $819,000. During the nine months ended September 30, 2022, we also realized a net decrease in cash of $10.7 million associated with the Falcon Merger and certain cash balances not contributed by our Predecessor.
Financing Activities
Cash flows provided by financing activities for the nine months ended September 30, 2022 totaled $397.0 million as compared to cash flows used in financing activities of $12.5 million for the nine months ended September 30, 2021. Borrowings under the Revolving Credit Facility for the nine months ended September 30, 2022 and 2021 were $196.9 million and $20.0 million, respectively, which were used to fund the Falcon Merger and other acquisitions of mineral and royalty interests. Repayments on our credit facility for the nine months ended September 30, 2022 and 2021 were $147.0 million and $41.6 million, respectively, largely provided by cash flows from operations. During the nine months ended September 30, 2022, we borrowed and repaid $425.0 million under the Bridge Loan
49
Facility, the proceeds from which were used to fund acquisitions of mineral and royalty interests. During the nine months ended September 30, 2022, we received proceeds of $444.5 million from the issuance of the 2026 Senior Notes, which were used to repay and extinguish the Bridge Loan Facility and for other general corporate purposes. Other financing cash outflows during the nine months ended September 30, 2022, included $14.9 million of costs incurred in connection with our entry into the Bridge Loan Facility, costs of $4.2 million incurred in connection with the issuance of the 2026 Senior Notes, costs of $4.0 million incurred in connection with amendments and restatements to our Revolving Credit Facility, dividends of $9.0 million paid to holders of Class A Common Stock, $50.5 million of distributions paid to temporary equity holders and $13.3 million of distributions paid to noncontrolling interests by our Predecessor. Other financing cash inflows during the nine months ended September 30, 2021 included $1.5 million of contributions by noncontrolling interests in our Predecessor and $8.0 million of partners’ capital contributions to our Predecessor.
Our Revolving Credit Facility
The Predecessor was party to the Predecessor Revolving Credit Facility. In October 2021, KMF Land as borrower, and Desert Peak, as parent, entered into the A&R Credit Agreement.
On the Closing Date, the A&R Credit Agreement was amended, restated, and refinanced in its entirety pursuant to the Credit Agreement. The Credit Agreement has a scheduled maturity date in June 2026. Pursuant to the terms and conditions of the Credit Agreement, the Lenders committed to providing a credit facility to Sitio OpCo in an aggregate principal amount of up to $750 million. The availability under the Credit Agreement, 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 of the Closing Date, the Credit Agreement has a $300 million borrowing base and $300 million elected commitment amount. As part of the aggregate commitments under the revolving advances, the Credit Agreement provides for letters of credit to be issued at the request of the borrower in an aggregate amount not to exceed $15 million. Existing letters of credit in place under the Revolving Credit Facility immediately prior to the Closing Date are continued and now deemed issued under and governed by the terms of the Credit Agreement.
Interest accrues on advances, at the borrower’s option, at an adjusted Term SOFR rate or a base rate, plus an applicable margin and credit spread adjustment. The fees for letters of credit are also based on the applicable margin. The applicable margin used in connection with interest rates and fees is based on the Borrowing Base Utilization Percentage (as defined in the Credit Agreement). The applicable margin for Term SOFR rate loans and letter of credit fees ranges from 2.500% to 3.500%, and the applicable margin for base rate loans ranges from 1.500% to 2.500%. The credit spread adjustment ranges from 0.100% to 0.250% depending on the applicable interest rate and interest rate period. The borrower will also pay a fee based on the borrowing base utilization percentage on the actual daily unused amount of the aggregate revolving commitments ranging from 0.375% to 0.500%.
The borrowings under the Credit Agreement are secured by liens on certain assets of the borrower, the borrower’s subsidiaries and Sitio Royalties GP, LLC, a Delaware limited liability company, and guaranteed by the borrower and the borrower’s subsidiaries. Proceeds from borrowings under the Credit Agreement may be used (a) for working capital, exploration and production operations, and other general company purposes including acquisitions, (b) for dividends to stockholders, (c) for payment of certain transaction fees and expenses, and (d) to repay third party debt of the borrower and its subsidiaries existing prior to the Closing Date.
The Credit Agreement contains customary representations, warranties, covenants and events of default, including, among others, a change of control event of default and limitations on the incurrence of indebtedness and liens, new lines of business, mergers, transactions with affiliates and burdensome agreements. During the continuance of an event of default, the Lenders may take a number of actions, including, among others, declaring the entire amount then outstanding under the Credit Agreement to be due and payable.
The Credit Agreement includes a financial covenant limiting, as of the last day of each fiscal quarter, the ratio of (a) (i) Total Net Debt (as defined in the Credit Agreement) as of such date to (ii) EBITDA (as defined in the Credit Agreement) for the period of four fiscal quarters ending on such day (the “Leverage Ratio”), to not more than 3.50 to 1.00, and (b) (i) consolidated current assets (including the available commitments under the Credit Agreement) to (ii) consolidated current liabilities (excluding current maturities under the Credit Agreement), to not less than 1.00 to 1.00, in each case, with certain rights to cure.
2026 Senior Notes
On September 21, 2022, Sitio OpCo, as issuer, and certain subsidiaries of Sitio OpCo, as guarantors, entered into the Note Purchase Agreement with certain institutional investors party thereto as holders and U.S. Bank Trust Company, National Association, as agent for the Holders.
Pursuant to the Note Purchase Agreement, Sitio OpCo issued the 2026 Senior Notes to the Holders in an aggregate principal amount of $450.0 million. Sitio OpCo used $425.0 million of the proceeds from the 2026 Senior Notes to repay in full all amounts outstanding under the Bridge Loan Facility with the remainder used for general corporate purposes. The 2026 Senior Notes mature on September 21, 2026.
50
Sitio OpCo may elect, at its option, to prepay the 2026 Senior Notes in whole or in part at any time, subject to (except as described below) payment of a premium determined in accordance with the table below based on the length of time between the issuance date and the prepayment date:
|
|
|
|
|
Period |
|
Premium |
|
Months 0 - 12 |
|
Customary “make-whole” premium plus 3.00% |
|
Months 13 - 24 |
|
|
3.00 |
% |
Months 25 - 36 |
|
|
1.00 |
% |
Months 37 - 48 |
|
|
0.00 |
% |
Interest accrues on the 2026 Senior Notes at an adjusted Term SOFR rate (including a 0.150% spread adjustment) for a three-month period plus a margin of 6.50%, unless the Agent determines that adequate and reasonable means do not exist for ascertaining the Term SOFR rate or the Requisite Holders (as defined in the Note Purchase Agreement) determine that the Term SOFR rate will not reflect the cost of maintaining their 2026 Senior Notes for the relevant period, in which case the 2026 Senior Notes will bear interest at a base rate (defined on the basis of the prime rate) plus a margin a of 5.50%. From and after the closing date of the Brigham Merger, the applicable margin will be reduced to 5.75% for 2026 Senior Notes bearing interest based on the adjusted Term SOFR rate and to 4.75% for 2026 Senior Notes bearing interest based on the base rate. Interest payments on the 2026 Senior Notes are due quarterly.
Sitio OpCo may elect, at its option, to prepay the 2026 Senior Notes, on the last business day of each calendar quarter in an amount equal to 2.50% of the initial principal amount of all the 2026 Senior Notes issued under the Notes Purchase Agreement, which prepayments will not require the payment of any premium (each, an “Optional Quarterly Payment”). If Sitio OpCo does not make an Optional Quarterly Payment on any quarterly payment date, the applicable margin on the 2026 Senior Notes will increase to 9.50% for 2026 Senior Notes bearing interest based on the adjusted Term SOFR rate and 8.50% for 2026 Senior Notes bearing interest based on the base rate. Subsequent to the closing of the Brigham Merger, if an Optional Quarterly Payment is not made, the margin will increase to 7.75% for 2026 Senior Notes bearing interest based on the adjusted Term SOFR rate and 6.75% for 2026 Senior Notes bearing interest based on the base rate. The increased margin will apply until the earlier of the date on which Sitio OpCo makes such Optional Quarterly Payment or the next quarterly payment date.
The Note Purchase Agreement includes, among other terms and conditions, a maximum leverage ratio covenant, as well as customary mandatory prepayments, representations, warranties, covenants and events of default, including, among others, a change of control event of default and limitations on the incurrence of indebtedness and liens, new lines of business, mergers, transactions with affiliates and burdensome agreements. During the continuance of an event of default, the Holders may take a number of actions, including, among others, declaring the entire amount of the 2026 Senior Notes and other amounts then outstanding under the Note Purchase Agreement to be due and payable. The Note Purchase Agreement requires Sitio OpCo to maintain a leverage ratio as of the last day of each fiscal quarter of not more than 3.50 to 1.00.
Bridge Loan Facility
On June 24, 2022, Sitio OpCo, as borrower, entered into an unsecured 364-Day Bridge Loan Agreement with Bank of America, N.A. as Administrative Agent for the Lenders, BofA Securities, Inc., as joint lead arranger and sole bookrunner, and Barclays Bank PLC and KeyBank National Association, as joint lead arrangers. The Bridge Loan Agreement provides for a 364-day Bridge Loan Facility in the aggregate principal amount of $250.0 million. The Bridge Loan Facility was fully repaid and extinguished on September 21, 2022 using proceeds from the issuance of the 2026 Senior Notes. Upon the closure of the facility, the Company recognized a loss on extinguishment of debt of $11.5 million associated with unamortized debt issuance costs and other fees incurred in connection with the payoff.
New and Revised Financial Accounting Standards
Refer to “Recent Accounting Pronouncements” in “Note 2 - Summary of Significant Accounting Policies” to our unaudited condensed consolidated financial statements for the nine months ended September 30, 2022 and 2021 for a discussion of recent accounting pronouncements.
Critical Accounting Policies and Related Estimates
The discussion and analysis of financial condition and results of operations are based upon our unaudited condensed 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
51
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 unaudited condensed 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 ASC 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 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 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
52
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.
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.
Contractual Obligations
As of September 30, 2022, we did not have any debt, capital lease obligations, operating lease obligations or long-term liabilities, other than borrowings under our Revolving Credit Facility, borrowings under the 2026 Senior Notes and three operating lease agreements for office space. Please see “—Our Revolving Credit Facility” for a description of our Revolving Credit Facility, “2026 Senior Notes” for a description of the 2026 Senior Notes and “Note 15 – Commitments and Contingencies” to our interim unaudited condensed consolidated financial statements for the nine months ended September 30, 2022 and 2021 for our contractual obligations under the office lease agreements.