Vitesse Energy, Inc. (VTS) FY 2023 MD&A
This page reproduces the company's own Item 7 MD&A text from the linked SEC filing. It is filer text, not grepcent analysis, scoring, or investment advice.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
You should read the following discussion of our results of operations and financial condition together with our Audited Consolidated Financial Statements and the notes thereto included under the section entitled “Index to Financial Statements,” as well as the discussion in Part I. Items 1 and 2. Business and Properties. This discussion contains forward-looking statements that involve risks and uncertainties. The forward-looking statements are not historical facts, but rather are based on current expectations, estimates, assumptions and projections about the oil and natural gas industry and our business and financial results. Our actual results could differ materially from the results contemplated by these forward-looking statements due to a number of factors, including those discussed in Part I. Item 1A. Risk Factors and “Cautionary Statement Concerning Forward-Looking Statements.”
Executive Overview
Our business strategy is focused on creating long-term stockholder value through the profitable acquisition, development and production of oil and natural gas assets at attractive rates of return, while maintaining a strong balance sheet and distributing a meaningful dividend to our stockholders. We invest in non-operated minority working and mineral interests in oil and natural gas properties with our core area of focus in the Williston Basin of North Dakota and Montana. We also have interests in wells in the Denver-Julesburg Basin located in Colorado and Wyoming and the Powder River Basin located in Wyoming. As of December 31, 2023, we had a working interest in 5,734 gross (157.5 net) productive wells and 224 gross (6.7 net) wells that were being drilled or completed, and an additional 363 gross (9.9 net) wells that had been permitted for development by our operators. Our estimated proved reserves as of December 31, 2023 were 40,595 MBoe (68% oil) and our average production was 11,889 Boe per day during the year ended December 31, 2023.
Our financial and operating performance for the year ended December 31, 2023 included the following:
■Total revenue of $233.9 million.
■Cash flows from operations of $141.9 million.
■Net loss of $19.7 million.
■Proved reserves of 40.6 MMBoe and $682.1 million PV-10 value at December 31, 2023, as estimated by our third-party reserve engineers using SEC guidelines.
■Total debt of $81.0 million at December 31, 2023.
■Paid $58.0 million in dividends to our equity holders.
See Part II. Item 7. Management Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Information for additional information about PV-10.
Industry Trends Impacting Our Business
Commodity prices are a significant factor impacting our acquisition and divestiture strategy, as well as the decisions of our operators in conducting their operations. Prices for oil and natural gas can be highly volatile. For instance, the COVID-19 pandemic and efforts to mitigate the spread of the disease, combined with OPEC actions in early 2020, led to spot and future prices of oil and natural gas falling to historic lows during the second quarter of 2020 and remaining depressed through much of 2020. Oil and gas operators responded by significantly decreasing drilling and completion activity, and by shutting in or curtailing production from a significant number of producing wells. Commodity prices, however, quickly reached pre-pandemic levels in the second half of 2021, and during 2022 increased further, in part as a result of the Russian invasion of Ukraine in combination with ongoing oil production limits from OPEC. In November 2023, certain members of OPEC and Russia and certain of its other allies (“OPEC+”) agreed to voluntary production/ export cuts of 2.2 million bpd for the first quarter of 2024 (subject to extension) from the 2024 required production levels. These voluntary cuts are in addition to (i) a production cut of 2 million bpd agreed to by the alliance in October 2022 and (ii) voluntary cuts by certain members of OPEC+ of 1.66 million bpd announced in April 2023 and subsequently extended through the end of 2024. In addition, while the impact of the ongoing conflicts between Russia and Ukraine and in the Middle East remain uncertain, these conflicts may have further global economic consequences, including disruptions of the global energy markets, inflation and supply chain constraints.
As a result of such commodity price volatility, which we expect to continue throughout 2024, our earnings and operating cash flows can vary substantially. While we do hedge a substantial portion of our production, we are still significantly subject to movements in commodity prices. Such volatility can make it difficult to predict future effects on our financial results and the decisions of our operators. Factors that we expect will continue to impact commodity prices include product demand connected with global economic conditions, inflationary factors, industry production and inventory levels, the United States Department of Energy’s future planned repurchases (or additional possible releases) of oil from the strategic petroleum reserve, technology advancements, production quotas or other actions imposed by OPEC countries, actions of regulators, and regional supply interruptions or fears thereof that may be caused by military conflicts (including invasion), civil unrest, pandemic or political uncertainty. Any of the foregoing can have a substantial impact on the prices of oil and natural gas, which in turn impacts the decision of our operators to drill and extract resources. Despite such commodity price volatility, we expect that our cash flow
54
Table of Contents
from operations and borrowing availability under our Revolving Credit Facility will allow us to meet our liquidity needs for the next twelve months.
Source of Our Revenues
We derive our revenues from the sale of oil and natural gas produced from our properties. Revenues are a function of the volume produced, the prevailing market price at the time of sale, oil quality, Btu content and transportation costs to market. We use derivative instruments to hedge future sales prices on a substantial, but varying, portion of our oil production. We have not hedged natural gas production since March 2022 due to the mismatch between our operators’ pricing formulas and settlement mechanics on natural gas hedges. We expect our derivative activities will help us achieve more predictable cash flows and reduce our exposure to downward price fluctuations. The use of derivative instruments has in the past, and may in the future, prevent us from realizing the full benefit of upward price movements but also mitigates the effects of declining price movements.
Principal Components of Our Cost Structure
Commodity price differentials. The price differential between our wellhead price for oil and the WTI benchmark price is primarily driven by the cost to transport oil via pipeline, train or truck to refineries. The price differential between our wellhead price for natural gas and the NYMEX benchmark price is primarily driven by Btu content along with gathering, processing and transportation costs.
Gain (loss) on commodity derivatives, net. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the prices of oil and gas. Gain (loss) on commodity derivatives, net is comprised of (1) cash gains and losses we recognize on settled commodity derivatives during the period, and (2) non-cash mark-to-market gains and losses we incur on commodity derivative instruments outstanding at period-end.
Lease operating expenses. Lease operating expenses are costs incurred to bring oil and natural gas out of the ground and to market, together with the costs incurred to maintain our producing properties. Such costs include field personnel compensation, saltwater disposal, utilities, maintenance, repairs and servicing expenses related to our oil and natural gas properties.
Production taxes. Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at market prices (not hedged prices) or at fixed rates established by federal, state or local taxing authorities. We seek to take full advantage of all credits and exemptions in our various taxing jurisdictions. In general, the production taxes we pay correlate to the changes in oil and natural gas revenues.
Depletion, depreciation, amortization, and accretion. Depletion, depreciation, amortization, and accretion (“DD&A”) includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas properties. As a successful efforts company, costs associated with the acquisition, drilling, and equipping of successful exploratory wells and costs of successful and unsuccessful development wells are capitalized. Accretion expense relates to the passage of time of our asset retirement obligations.
General and administrative expenses. General and administrative expenses include overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our acquisition and development operations, franchise taxes, audit and other professional fees and legal compliance. For fiscal 2022 and 2023, general and administrative expenses included non-recurring costs related to the Spin-Off.
Interest expense. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our Revolving Credit Facility and prior to the Spin-Off, under the Prior Revolving Credit Facility. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We do not capitalize any portion of the interest paid on applicable borrowings. We include the amortization of deferred financing costs, commitment fees and annual agency fees as interest expense.
Impairment expense. Under the successful efforts method of accounting, we review our oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Whenever we conclude the carrying value may not be recoverable, we estimate the expected undiscounted future net cash flows of our oil and natural gas properties using proved and risked probable and possible reserves based on our development plans and best estimate of future production, commodity pricing, reserve risking, gathering, processing and transportation deductions, production tax rates, lease operating expenses and future development costs. We compare such undiscounted future net cash flows to the carrying amount of the oil and natural gas properties in each depletion pool to determine if the carrying amount is recoverable. If the undiscounted future net cash flows exceed the carrying amount of the aggregated oil and natural gas properties, no impairment is recorded. If the carrying amount of the oil and natural gas properties exceeds the undiscounted future net cash flows, we will record an impairment expense to reduce the carrying value to fair value as of the balance sheet date. The factors used to determine fair value may include, but are not limited to, recent sales prices of comparable properties, indications from marketing activities, the present value of future revenues, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the projected cash flows.
55
Table of Contents
Income tax expense. Our provision for taxes includes both federal and state taxes. We record our federal income taxes in accordance with accounting for income taxes under GAAP, which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized. Vitesse Energy, our Predecessor, was a limited liability company. Accordingly, no provision for income taxes was recorded, as the income, deductions, expenses, and credits of the Predecessor were reported on the income tax returns of it’s members.
Selected Factors That Affect Our Operating Results
Our revenues, cash flows from operations and future growth depend substantially upon:
■the timing and success of drilling and production activities by our operating partners;
■the prices and the supply and demand for oil, natural gas and NGLs;
■the quantity of oil and natural gas production from the wells in which we participate;
■changes in the fair value of the derivative instruments;
■our ability to continue to identify and acquire high-quality acreage and drilling opportunities; and
■the level of our operating expenses.
In addition to the factors that affect companies in our industry generally, the location of substantially all of our acreage and wells in the Williston, Denver-Julesburg and Powder River Basins subjects our operating results to factors specific to these regions. These factors include the potential adverse impact of weather on drilling, production and transportation activities, particularly during the winter and spring months, as well as infrastructure limitations, transportation capacity, regulatory matters and other factors that may specifically affect one or more of these regions.
Market Conditions
The price of oil can vary depending on the market in which it is sold and the means of transportation used to transport the oil to market, particularly in the Williston Basin where a substantial majority of our revenues are derived. Additional pipeline infrastructure has increased takeaway capacity in the Williston Basin which has improved wellhead values in the region.
The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand. Because our oil and gas revenues are heavily weighted toward oil, we are more significantly impacted by changes in oil prices than by changes in the price of natural gas. World-wide supply in terms of output, especially production from properties within the United States, the production quota set by OPEC, the conflicts in Ukraine and in the Middle East and the strength of the U.S. dollar can adversely impact oil prices.
The price at which our oil production is sold typically reflects a discount to the WTI benchmark price. The price at which our natural gas production is sold may reflect either a discount or premium to the Henry Hub benchmark price. Thus, our operating results are also affected by changes in the oil price differentials between the applicable benchmark and the sales prices we receive for our oil production. Our oil price differential to the weighted average WTI benchmark price during the year ended December 31, 2023 was negative $4.19 per Bbl, as compared to a negative $3.39 per Bbl during the year ended December 31, 2022, primarily due to less favorable local market pricing, including gathering and transportation costs, as compared to the benchmark price. Our net realized natural gas price during the year ended December 31, 2023 was $1.88 per Mcf, representing a 74% realization relative to average Henry Hub pricing, compared to a net realized natural gas price of $6.64 per Mcf during the year ended December 31, 2022, representing a 103% realization relative to average Henry Hub pricing. Fluctuations in our natural gas price differentials and realizations are due to several factors such as NGL value net of processing costs, gathering, and transportation costs, takeaway capacity relative to production levels, regional storage capacity, seasonal demand for heating fuel and seasonal refinery maintenance temporarily depressing demand. The exact impact of each of these items is difficult to quantify as each of our operators pass through these costs in a different manner.
Historically, commodity prices have been volatile and we expect the volatility to continue in the future. Factors impacting the future oil supply balance include world-wide demand for oil, as well as the growth in domestic oil production.
Prices for various quantities of oil, natural gas and NGLs significantly impact our revenues and cash flows. The following table lists average NYMEX prices for oil and natural gas for the periods presented.
56
Table of Contents
| YEAR ENDED DECEMBER 31, | YEAR ENDED NOVEMBER 30, | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Average NYMEX Prices (1) | 2023 | 2022 | 2021 | 2021 | ||||||||||
| WTI Oil (per Bbl) | $ | 77.58 | $ | 94.90 | $ | 68.14 | $ | 65.97 | ||||||
| Natural Gas (per MMBtu) | 2.53 | 6.45 | 3.89 | 3.79 |
(1)Based on a simple average of daily NYMEX closing prices.
The average calendar 2023 WTI oil price was $77.58 per Bbl or 18% lower than the average WTI price per Bbl in calendar 2022. Our settled derivatives increased our realized oil price per Bbl by $0.40 in calendar 2023 and decreased our realized oil price per Bbl by $18.07 in calendar 2022. Our average 2023 realized oil price per Bbl after reflecting settled derivatives was $73.99 compared to $72.66 in 2022. The average calendar 2023 NYMEX natural gas price was $2.53 per MMBtu, or 61% lower than the average NYMEX price per MMBtu in calendar 2022. We had no gas price derivatives in place in calendar 2023 and our settled derivatives decreased our realized natural gas price per Mcf by $0.08 in 2022. Our 2023 realized natural gas price per Mcf after reflecting settled derivatives was $1.88 compared to $6.56 in 2022, which was primarily driven by lower NYMEX pricing for natural gas and gas realization.
We employ a hedging program that mitigates the risk associated with fluctuations in commodity prices. For detailed information on our commodity hedging program, see Part II. Item 7A. Quantitative and Qualitative Disclosures about Market Risk and Notes to Consolidated Financial Statements—Note 6—Derivative Instruments.
Another significant factor affecting our operating results is drilling costs. The cost of drilling wells can vary significantly, driven in part by volatility in commodity prices that can substantially impact the level of drilling activity. Generally, higher oil prices have led to increased drilling activity, with the increased demand for drilling and completion services driving these costs higher. Lower oil prices have generally had the opposite effect. In addition, individual components of the cost can vary depending on numerous factors such as the length of the horizontal lateral, the number of fracture stimulation stages, and the type and amount of proppant.
Results of Operations
Change in Estimate that is Inseparable from a Change in Accounting Principle
Effective January 1, 2023, the Company changed its method of recording gathering and transportation (“GT”) costs. Under the current method, GT costs are presented as a deduction to oil and gas revenue, following how these items are reported to us by operators. Prior to January 1, 2023, under our previous method, we determined the GT costs that were reported within production expense versus revenue deductions based on our best estimates using information from all our operators in aggregate. Although the change does not have a material impact to the financial statements the change in methodology has been applied on a retrospective basis to the prior periods presented in order to conform to the current period presentation. This change results in a reclassification within the statements of operations and has no balance sheet impact, nor does it impact net income, operating income, the gross margin we generate from our interests in oil and gas properties, or cash flows for any period.
57
Table of Contents
Year Ended December 31, 2023 Compared with Year Ended December 31, 2022
The following table sets forth selected operating data for the periods indicated.
| YEAR ENDED DECEMBER 31, | INCREASE (DECREASE) | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| ($ in thousands, except per unit data) | 2023 | 2022 | AMOUNT | PERCENT | ||||||||||
| Operating Results: | ||||||||||||||
| Revenue | ||||||||||||||
| Oil | $ | 218,396 | $ | 233,622 | $ | (15,226) | (7 | %) | ||||||
| Natural gas | 15,509 | 48,268 | (32,759) | (68 | %) | |||||||||
| Total revenue | $ | 233,905 | $ | 281,890 | $ | (47,985) | (17 | %) | ||||||
| Operating Expenses | ||||||||||||||
| Lease operating expense | $ | 39,514 | $ | 31,133 | $ | 8,381 | 27 | % | ||||||
| Production taxes | 21,625 | 24,092 | (2,467) | (10 | %) | |||||||||
| General and administrative | 23,934 | 19,833 | 4,101 | 21 | % | |||||||||
| Depletion, depreciation, amortization, and accretion | 81,745 | 63,732 | 18,013 | 28 | % | |||||||||
| Equity-based compensation | 32,233 | (10,766) | 42,999 | *nm | ||||||||||
| Interest Expense | $ | 5,276 | $ | 4,153 | $ | 1,123 | 27 | % | ||||||
| Income Tax Expense | $ | 61,946 | $ | — | $ | 61,946 | *nm | |||||||
| Commodity Derivative Gain (Loss) | $ | 12,484 | $ | (30,830) | $ | 43,314 | 140 | % | ||||||
| Production Data: | ||||||||||||||
| Oil (MBbls) | 2,968 | 2,575 | 393 | 15 | % | |||||||||
| Natural gas (MMcf) | 8,232 | 7,274 | 958 | 13 | % | |||||||||
| Combined volumes (MBoe) | 4,340 | 3,787 | 553 | 15 | % | |||||||||
| Daily combined volumes (Boe/d) | 11,889 | 10,376 | 1,513 | 15 | % | |||||||||
| Average Realized Prices before Hedging: | ||||||||||||||
| Oil (per Bbl) | $ | 73.59 | $ | 90.73 | $ | (17.14) | (19 | %) | ||||||
| Natural gas (per Mcf) | 1.88 | 6.64 | (4.76) | (72 | %) | |||||||||
| Combined (per Boe) | 53.90 | 74.43 | (20.53) | (28 | %) | |||||||||
| Average Realized Prices with Hedging: | ||||||||||||||
| Oil (per Bbl) | $ | 73.99 | $ | 72.66 | $ | 1.33 | 2 | % | ||||||
| Natural gas (per Mcf) | 1.88 | 6.56 | (4.68) | (71 | %) | |||||||||
| Combined (per Boe) | 54.17 | 61.99 | (7.82) | (13 | %) | |||||||||
| Average Costs (per Boe): | ||||||||||||||
| Lease operating expense | $ | 9.11 | $ | 8.22 | $ | 0.89 | 11 | % | ||||||
| Production taxes | 4.98 | 6.36 | (1.38) | (22 | %) | |||||||||
| General and administrative | 5.52 | 5.24 | 0.28 | 5 | % | |||||||||
| Depletion, depreciation, amortization, and accretion | 18.84 | 16.83 | 2.01 | 12 | % |
*Not meaningful
Oil and Natural Gas Revenue and Volumes. Oil and natural gas revenue decreased to $233.9 million for the year ended December 31, 2023 from $281.9 million for the year ended December 31, 2022. The decrease in oil and natural gas revenue was due to a 28% decrease in the average realized prices per Boe before hedging, and was partially offset by a 15% increase in production volumes for the year ended December 31, 2023. The decrease in average realized prices per Boe before hedging decreased oil and natural gas revenue by approximately $77.7 million, while the increase in production volumes increased oil and natural gas revenue by approximately $29.8 million.
The decreases in realized oil and natural gas prices were primarily due to lower benchmark commodity prices in the year ended December 31, 2023 as compared to the year ended December 31, 2022, as well as increased differentials. Our oil price differential to the weighted average benchmark price during the year ended December 31, 2023 was negative $4.19 per Bbl, as compared to a negative $3.39 per Bbl during the year ended December 31, 2022, primarily due to less favorable local market pricing as compared to the benchmark price. Our net realized natural gas price during the year ended December 31, 2023 was $1.88 per Mcf, representing a 74% realization relative to the weighted average NYMEX natural gas price, compared to a net realized natural gas price of $6.64 per Mcf during the year ended December 31, 2022, representing a 103% realization relative to the weighted average NYMEX natural gas price. Fluctuations in our natural gas price differentials and realizations are due to several factors such as NGL value net of processing costs, gathering and transportation fees, takeaway capacity relative to production
58
Table of Contents
levels, regional storage capacity, seasonal demand for heating fuel and seasonal refinery maintenance temporarily depressing demand. The exact impact of each of these items is difficult to quantify as each of our operators pass through these costs in a different manner.
Lease Operating Expense. Lease operating expense increased to $9.11 per Boe for the year ended December 31, 2023 from $8.22 per Boe for the year ended December 31, 2022. The increase per Boe for the year ended December 31, 2023 compared with the year ended December 31, 2022 was related to increased workover operations and higher service costs. The increased workover costs were responsible for approximately $0.48/Boe of the increase and should result in increased production when these wells return to production.
Production Tax Expense. Total production taxes decreased to $21.6 million for the year ended December 31, 2023 from $24.1 million for the year ended December 31, 2022, primarily due to the decrease in oil and gas revenue in 2023. Production taxes are primarily based on oil revenue and natural gas production, excluding gains and losses associated with hedging activities. Production taxes as a percentage of oil and natural gas sales before hedging adjustments were 9.2% and 8.5% for the years ended December 31, 2023 and 2022, respectively. The increase in the production tax rate for the year ended December 31, 2023 was primarily due to a higher ratio of oil revenue to total revenue, since oil revenue is taxed at a higher rate than gas revenue.
General and Administrative Expense. General and administrative expense increased to $23.9 million for the year ended December 31, 2023 from $19.8 million for the year ended December 31, 2022. General and administrative expense on a per Boe basis increased to $5.52 for the year ended December 31, 2023 from $5.24 for the year ended December 31, 2022. Costs related to the Spin -Off are included in both periods. Excluding costs related to the Spin-Off, the per Boe rate for the years ended December 31, 2023 and 2022 would have been $3.94 and $3.15, respectively. The increase in general and administrative expense per Boe, excluding the Spin-Off costs, was primarily due to higher costs associated with being a public company.
DD&A. DD&A increased to $81.7 million for the year ended December 31, 2023 compared with $63.7 million for the year ended December 31, 2022. The increase of $18.0 million or 28% was the result of a 15% increase in production and a 12% increase in the DD&A rate for the year ended December 31, 2023 compared with the year ended December 31, 2022. The increase in production accounted for a $10.4 million increase in DD&A expense while the increase in the DD&A rate accounted for a $7.6 million increase in DD&A expense.
For the year ended December 31, 2023, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate (excluding depreciation, amortization and accretion) of $18.68 per Boe compared with $16.71 per Boe for the year ended December 31, 2022. The increase in the depletion rate was driven by a combination of decreased oil and natural gas reserves related to the lower oil and natural gas prices and the impact of acquisitions in the year ended December 31, 2023.
Equity-based Compensation. The Company’s long-term incentive plan (“LTIP”) provides for the granting of various forms of equity-based awards, including restricted stock units, performance units, stock options, stock appreciation rights, restricted stock, cash awards and other stock-based awards to employees, directors and consultants of the Company. Through December 31, 2023, the Company granted 3,152,247 restricted stock units, net of forfeitures, to employees and directors at a weighted-average grant date fair value of $14.99 per share. For restricted stock units, the Company recognizes the grant date fair-value of stock-based compensation awards expected to vest over the requisite service period as stock-based compensation expense on a straight-line basis except when provisions are present that accelerate vesting. Retirement vesting provisions in some of the awards resulted in 1,863,000 restricted stock units being expensed upon award. Equity-based compensation expense was $32.2 million for the year ended December 31, 2023.
Unit-based compensation expense was previously recorded by our Predecessor for in-substance call options granted to the founding members of management which are classified as liabilities and recorded at estimated fair value at each period end. Unit-based compensation expense was also recognized for management incentive units granted to other employees which are classified as liabilities until the holder has borne the risk of unit ownership. Unit-based compensation expense was recorded as these units vested and expense or contra-expense was recognized as the estimated fair value of the liability changed with market conditions. Unit-based compensation contra-expense was $10.8 million for the year ended December 31, 2022.
Interest Expense. Interest expense increased to $5.3 million for the year ended December 31, 2023 from $4.2 million for the year ended December 31, 2022. The increase for the year ended December 31, 2023 was due to a higher SOFR interest rate in the year ended December 31, 2023 despite a lower average outstanding balance on our Revolving Credit Facility during the year ended December 31, 2023 compared to 2022. The higher interest rate was due to increases to the federal funds rate by the Federal Reserve throughout 2022 and 2023.
Commodity Derivative Gain (Loss). The net commodity derivative gain was $12.5 million for the year ended December 31, 2023 compared with a loss of $30.8 million for the year ended December 31, 2022. Gain (Loss) on Commodity Derivatives is comprised of (1) cash gains and losses we recognize on settled commodity derivative instruments during the period, and (2) unsettled gains and losses we incur on commodity derivative instruments outstanding at period-end.
59
Table of Contents
The mark-to-market fair value of the unsettled commodity derivative instruments will generally be inversely related to the price movement of the underlying commodity. If commodity price trends reverse from period to period, prior unrealized gains may become unrealized losses and vice versa. These unrealized gains and losses will impact our net income in the period reported. The mark-to-market fair value can create non-cash volatility in our reported earnings during periods of commodity price volatility. We have experienced such volatility in the past and are likely to experience it in the future. Gains on our derivatives generally indicate lower oil revenues in the future while losses indicate higher future oil revenues.
The table below summarizes our commodity derivative gains and losses that were recorded in the periods presented.
| YEAR END DECEMBER 31, | ||||||
|---|---|---|---|---|---|---|
| (in thousands) | 2023 | 2022 | ||||
| Realized gain (loss) on commodity derivatives (1) | $ | 1,166 | $ | (47,124) | ||
| Unrealized gain (loss) on commodity derivatives (1) | 11,318 | $ | 16,294 | |||
| Total commodity derivative gain (loss) | $ | 12,484 | $ | (30,830) |
(1)Realized and unrealized gains and losses on commodity derivatives are presented herein as separate line items but are combined for a total commodity derivative gain (loss) in the consolidated statements of operations included in this Annual Report on Form 10-K. Management believes the separate presentation of the realized and unrealized commodity derivative gains and losses is useful because the realized cash settlement portion provides a better understanding of our hedge position.
In 2023, approximately 49% of our oil volumes and none of our natural gas volumes were covered by financial hedges, which resulted in a realized gain on oil derivatives of $1.2 million. In 2022, approximately 55% of our oil volumes and 6% of our natural gas volumes were covered by financial hedges, which resulted in a realized loss on oil derivatives of $46.5 million and a realized loss on natural gas derivatives of $0.6 million after settlements.
At December 31, 2023, all of our derivative contracts were recorded at their fair value, which was a net asset of $11.1 million, an increase of $11.3 million from the $0.2 million net liability recorded as of December 31, 2022. The increase was due to changes to forward commodity prices relative to prices on our open commodity derivative contracts and new contracts entered into in the year ended December 31, 2023.
Income Tax Expense. We recorded income tax expense of $61.9 million for the year ended December 31, 2023 related to federal and state income taxes, including $44.1 million recorded at Spin-Off as discussed below. The provision for income taxes for the year ended December 31, 2023 differs from the amount that would be provided by applying the statutory U.S. federal income tax rate of 21% to pre-tax income primarily due to §162(m) limitations on certain covered employee compensation and state income taxes. No income tax expense was recorded for the year ended December 31, 2022 because the Predecessor was treated as a nontaxable partnership for income tax purposes for that period.
During the year ended December 31, 2023, the Predecessor was contributed into Vitesse resulting in a change in tax status and the recording of a $44.1 million deferred tax liability related to the temporary difference between the tax and GAAP basis of the assets of the Predecessor and an offsetting charge to income tax expense.
60
Table of Contents
Change in Fiscal Year End
On November 30, 2021, our Board and the Board of Managers of our Predecessor approved a change in our fiscal year end and that of our Predecessor from November 30 to December 31. As a result, Vitesse Energy's 2022 fiscal year began on January 1, 2022 and ended on December 31, 2022 and there was a transition period from December 1, 2021 to December 31, 2021 (the “Transition Period”). For the purposes of this discussion and analysis we have presented the income statement for the year ended December 31, 2021 in order to provide a comparison to the year ended December 31, 2022. The income statement for the year ended December 31, 2021 was derived as follows:
| YEAR ENDED NOVEMBER 30, 2021 | PLUS: MONTH ENDED DECEMBER 31, 2021 (TRANSITION PERIOD) | LESS: MONTH ENDED DECEMBER 31, 2020 | YEAR ENDED DECEMBER 31, 2021 | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (in thousands) | ||||||||||||||
| Oil | $ | 144,818 | $ | 14,797 | $ | 8,052 | $ | 151,563 | ||||||
| Natural gas | 23,017 | 1,669 | 214 | 24,472 | ||||||||||
| Total revenue | 167,835 | 16,466 | 8,266 | 176,035 | ||||||||||
| Operating Expenses | ||||||||||||||
| Lease operating expense | 26,567 | 2,272 | 1,689 | 27,150 | ||||||||||
| Production taxes | 14,535 | 1,340 | 863 | 15,012 | ||||||||||
| General and administrative | 10,581 | 950 | 793 | 10,738 | ||||||||||
| Depletion, depreciation, amortization, and accretion | 60,846 | 5,417 | 5,380 | 60,883 | ||||||||||
| Equity-based compensation | 1,409 | 2,628 | — | 4,037 | ||||||||||
| Total operating expenses | 113,938 | 12,607 | 8,725 | 117,820 | ||||||||||
| Operating Income (Loss) | 53,897 | 3,859 | (459) | 58,215 | ||||||||||
| Other (Expense) Income | ||||||||||||||
| Commodity derivative (loss) gain, net | (32,590) | (10,982) | (3,681) | (39,891) | ||||||||||
| Interest expense | (3,207) | (237) | (319) | (3,125) | ||||||||||
| Other income | 14 | 1 | 1 | 14 | ||||||||||
| Total other (expense) income | (35,783) | (11,218) | (3,999) | (43,002) | ||||||||||
| Net Income (Loss) | $ | 18,114 | $ | (7,359) | $ | (4,458) | $ | 15,213 |
61
Table of Contents
Year Ended December 31, 2022 Compared with Year Ended December 31, 2021
The following table sets forth selected operating data for the periods indicated.
| YEAR ENDED DECEMBER 31, | INCREASE (DECREASE) | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (in thousands, except per unit data) | 2022 | 2021 | AMOUNT | PERCENT | ||||||||||
| Operating Results: | ||||||||||||||
| Revenue | ||||||||||||||
| Oil | $ | 233,622 | $ | 151,563 | $ | 82,059 | 54 | % | ||||||
| Natural gas | 48,268 | 24,472 | 23,796 | 97 | % | |||||||||
| Total revenue | $ | 281,890 | $ | 176,035 | $ | 105,855 | 60 | % | ||||||
| Operating Expenses | ||||||||||||||
| Lease operating expense | $ | 31,133 | $ | 27,150 | $ | 3,983 | 15 | % | ||||||
| Production taxes | 24,092 | 15,012 | 9,080 | 60 | % | |||||||||
| General and administrative | 19,833 | 10,738 | 9,095 | 85 | % | |||||||||
| Depletion, depreciation, amortization, and accretion | 63,732 | 60,883 | 2,849 | 5 | % | |||||||||
| Equity-based compensation | (10,766) | 4,037 | (14,803) | *nm | ||||||||||
| Interest Expense | $ | 4,153 | $ | 3,125 | $ | 1,028 | 33 | % | ||||||
| Commodity Derivative Gain (Loss) | $ | (30,830) | $ | (39,891) | $ | 9,061 | 23 | % | ||||||
| Production Data: | ||||||||||||||
| Oil (MBbls) | 2,575 | 2,447 | 128 | 5 | % | |||||||||
| Natural gas (MMcf) | 7,274 | 7,084 | 190 | 3 | % | |||||||||
| Combined volumes (MBoe) | 3,787 | 3,627 | 160 | 4 | % | |||||||||
| Daily combined volumes (Boe/d) | 10,376 | 9,937 | 439 | 4 | % | |||||||||
| Average Realized Prices before Hedging: | ||||||||||||||
| Oil (per Bbl) | $ | 90.73 | $ | 61.94 | $ | 28.79 | 46 | % | ||||||
| Natural gas (per Mcf) | 6.64 | 3.45 | 3.19 | 92 | % | |||||||||
| Combined (per Boe) | 74.43 | 48.53 | 25.90 | 53 | % | |||||||||
| Average Realized Prices with Hedging: | ||||||||||||||
| Oil (per Bbl) | $ | 72.66 | $ | 55.36 | $ | 17.30 | 31 | % | ||||||
| Natural gas (per Mcf) | 6.56 | 3.34 | 3.22 | 96 | % | |||||||||
| Combined (per Boe) | 61.99 | 43.87 | 18.12 | 41 | % | |||||||||
| Average Costs (per Boe): | ||||||||||||||
| Lease operating expense | $ | 8.22 | $ | 7.49 | $ | 0.73 | 10 | % | ||||||
| Production taxes | 6.36 | 4.14 | 2.22 | 54 | % | |||||||||
| General and administrative | 5.24 | 2.96 | 2.28 | 77 | % | |||||||||
| Depletion, depreciation, amortization, and accretion | 16.83 | 16.79 | 0.04 | — | % |
*Not meaningful
Oil and Natural Gas Revenue and Volumes. Oil and natural gas revenue increased to $281.9 million for the year ended December 31, 2022 from $176.0 million for the year ended December 31, 2021. The increase in oil and natural gas revenue was due to a 53% increase in the average realized prices per Boe before hedging, along with a 4% increase in production volumes for the year ended December 31, 2022. The increase in average realized prices per Boe before hedging increased oil and natural gas revenue by approximately $93.9 million, while the increase in production volumes increased oil and natural gas revenue by approximately $12.0 million.
Our oil price differential to the weighted average WTI benchmark price during the year ended December 31, 2022 was negative $3.39 per Bbl as compared to a negative $6.11 per Bbl during the year ended December 31, 2021, primarily due to favorable local market pricing as compared to the weighted average benchmark price. Our net realized natural gas price during the year ended December 31, 2022 was $6.56 per Mcf, representing a 103% realization relative to the weighted average NYMEX natural gas price, compared to a net realized natural gas price of $3.34 per Mcf during the year ended December 31, 2021, representing a 92% realization relative to weighted average NYMEX natural gas price. Fluctuations in our price differentials and realizations are due to several factors such as NGL value net of processing costs, gathering and transportation fees, takeaway capacity relative to production levels, regional storage capacity, seasonal demand for heating fuel and seasonal refinery maintenance temporarily depressing demand. The exact impact of each of these items is difficult to quantify as each of our operators pass through these costs in a different manner.
62
Table of Contents
Lease Operating Expense. Lease operating expense increased to $8.22 per Boe for the year ended December 31, 2022 from $7.49 per Boe for the year ended December 31, 2021. The increase per Boe for the year ended December 31, 2022 compared with the year ended December 31, 2021 was primarily related to higher expense related to workovers and inflationary pressure on service costs. The increased workover costs were responsible for approximately $0.60/Boe of the increase.
Production Tax Expense. Total production taxes increased to $24.1 million for the year ended December 31, 2022 from $15.0 million for the year ended December 31, 2021. Production taxes are primarily based on oil revenue and gas production, excluding gains and losses associated with hedging activities. Production taxes as a percentage of oil and natural gas sales before hedging adjustments were 8.5% for both years ended December 31, 2022 and 2021.
General and Administrative Expense. General and administrative expense increased to $19.8 million for the year ended December 31, 2022 from $10.7 million for the year ended December 31, 2021. General and administrative expense on a per Boe basis increased to $5.24 for the year ended December 31, 2022 from $2.96 for the year ended December 31, 2021. The increase in general and administrative expense on a per Boe basis was primarily related to costs related to the Spin-Off of $7.9 million. Excluding costs related to the Spin-Off the per BOE rate in calendar 2022 would have been $3.15 per BOE. The slight increase in general and administrative expense per BOE, excluding the Spin-Off costs, was primarily due to legal fees incurred for our litigation against one operator regarding excessive deductions taken against our revenue.
DD&A. DD&A increased to $63.7 million for the year ended December 31, 2022 compared with $60.9 million for the year ended December 31, 2021. The increase of $2.8 million, or 5% was the result of a 4% increase in production and a minimal increase in the DD&A rate for the year ended December 31, 2022 compared with the year ended December 31, 2021. The increase in production accounted for a $2.7 million increase in DD&A expense while the increase in the DD&A rate accounted for a $0.1 million increase in DD&A expense.
Unit-based Compensation. Unit-based compensation expense is recorded for in-substance call options granted to the founding members of management which are classified as liabilities and recorded at estimated fair value at each period end. Unit-based compensation expense is also recognized for management incentive units granted to other employees which are classified as liabilities until the holder has borne the risk of unit ownership. Unit-based compensation expense is recorded as these units vest and expense or contra-expense is recognized as the estimated fair value of the liability changes with market conditions. Unit-based compensation expense was a negative $10.8 million for the year ended December 31, 2022 compared to $4.0 million for the year ended December 31, 2021 primarily due to a reduced value of the options due to a shortened time until exercise and lower volatility as these instruments were settled in conjunction with the Spin-Off.
Interest Expense. Interest expense increased to $4.2 million for the year ended December 31, 2022 from $3.1 million for the year ended December 31, 2021. The increase for the year ended December 31, 2022 was due to a higher SOFR interest rate in the year ended December 31, 2022 despite the balance on our Prior Revolving Credit Facility declining to $48.0 million at December 31, 2022 from $68.0 million at December 31, 2021. The higher interest rate was due to increases to the federal funds rate by the Federal Reserve throughout 2022.
Commodity Derivative Gain (Loss). Commodity derivative loss was $30.8 million for the year ended December 31, 2022 compared with a loss of $39.9 million for the year ended December 31, 2021. Gain (Loss) on Commodity Derivatives is comprised of (1) cash gains and losses we recognize on settled commodity derivative instruments during the period, and (2) unsettled gains and losses we incur on commodity derivative instruments outstanding at period-end.
The mark-to-market fair value of the unsettled commodity derivative instruments will generally be inversely related to the price movement of the underlying commodity. If commodity price trends reverse from period to period, prior unrealized gains may become unrealized losses and vice versa. These unrealized gains and losses will impact our net income in the period reported. The mark-to-market fair value can create non-cash volatility in our reported earnings during periods of commodity price volatility. We have experienced such volatility in the past and are likely to experience it in the future. Gains on our derivatives generally indicate lower oil revenues in the future while losses indicate higher future oil revenues.
63
Table of Contents
The table below summarizes our commodity derivative gains and losses that were recorded in the periods presented.
| YEAR END DECEMBER 31, | ||||||
|---|---|---|---|---|---|---|
| (in thousands) | 2022 | 2021 | ||||
| Realized gain (loss) on commodity derivatives (1) | $ | (47,124) | $ | (16,914) | ||
| Unrealized gain (loss) on commodity derivatives (1) | 16,294 | (22,977) | ||||
| Total commodity derivative gain (loss) | $ | (30,830) | $ | (39,891) |
(1)Realized and unrealized gains and losses on commodity derivatives are presented herein as separate line items but are combined for a total commodity derivative gain (loss) in the consolidated statements of operations included in this Annual Report on Form 10-K. Management believes the separate presentation of the realized and unrealized commodity derivative gains and losses is useful because the realized cash settlement portion provides a better understanding of our hedge position.
In 2022, approximately 55% of our oil volumes and 6% of our natural gas volumes were covered by financial hedges, which resulted in a realized loss on oil derivatives of $46.5 million and a realized loss on natural gas derivatives of $0.6 million after settlements. In 2021, approximately 47% of our oil volumes and 11% of our natural gas volumes were subject to financial hedges, which resulted in a realized loss on oil derivatives of $16.1 million and a realized loss on natural gas derivatives of $0.8 million after settlements.
Liquidity and Capital Resources
Overview. At December 31, 2023, we had $0.6 million of unrestricted cash on hand and $164.0 million available under our borrowing base. At December 31, 2022, we had $10.0 million of unrestricted cash on hand and $152.0 million available under our borrowing base in our Prior Revolving Credit Facility. We expect that our liquidity going forward will be primarily derived from cash flows from our operations, cash on hand and availability under the Revolving Credit Facility and that these sources of liquidity will be sufficient to provide us the ability to fund our material cash requirements for the next twelve months, as described below, including our planned capital expenditures program, as well as dividends and our share repurchase program. We may need to fund acquisitions or other business opportunities that support our strategy through additional borrowings under our Revolving Credit Facility or the issuance of equity or debt. Our primary uses of capital have been for the acquisition and development of our oil and natural gas properties and dividend payments. We continually monitor potential capital sources for opportunities to enhance liquidity or otherwise improve our financial position.
Working Capital. Our working capital balance fluctuates as a result of changes in commodity pricing and production volumes, the collection of revenue receivables, expenditures related to our acquisition and development, and production operations and the impact of our outstanding commodity derivative instruments. Excess liquidity was retained at December 31, 2022 in anticipation of fees related to the Spin-Off that were paid in early 2023.
At December 31, 2023, we had a working capital deficit of $2.1 million, compared to a surplus of $17.7 million at December 31, 2022. Current assets increased by $4.0 million while current liabilities increased by $23.7 million at December 31, 2023, compared to December 31, 2022. The increase in current assets in 2023 as compared to 2022 was primarily due to an increase of $7.9 million in our commodity derivative instruments due to forward oil price decreases and more advantageous hedge instruments in place at December 31, 2023, and an increase of $3.5 million in revenue receivable primarily due to higher oil and natural gas revenue in the fourth quarter, partially offset by a decreased cash balance of $9.5 million. The change in current liabilities in 2023 as compared to 2022 was primarily due to an increase of $27.1 million in accounts payable and accrued liabilities as a result of increased development activity offset by a decrease of $3.4 million in derivative instrument liabilities as a result of forward oil price decreases and more advantageous hedge instruments in place at December 31, 2023.
Cash Flows. Our cash flows for the years ended December 31, 2023, December 31, 2022 and November 30, 2021 and the month ended December 31, 2021 are presented below:
| FOR THE YEARS ENDED DECEMBER 31, | FOR THE MONTH ENDED DECEMBER 31, | FOR THE YEAR ENDED NOVEMBER 30, | ||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (in thousands) | 2023 | 2022 | 2021 | 2021 | ||||||||||
| Cash flows provided by operating activities | $ | 141,942 | $ | 147,041 | $ | 12,520 | $ | 86,971 | ||||||
| Cash flows used in investing activities | (120,666) | (84,583) | (3,956) | (43,317) | ||||||||||
| Cash flows used in financing activities | (30,731) | (57,807) | (6,009) | (42,587) | ||||||||||
| Net (decrease) increase in cash | $ | (9,455) | $ | 4,651 | $ | 2,555 | $ | 1,067 |
During the year ended December 31, 2023, we generated $141.9 million of cash from operations, a decrease of 3% from the year ended December 31, 2022 despite a 17% decrease in total revenue. During the year ended December 31, 2022, we generated
64
Table of Contents
$147.0 million of cash from operating activities, an increase of $60.1 million from the year ended November 30, 2021. Cash flows from operations are primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivative contracts, and by changes in working capital. Any interim cash needs are funded by cash on hand, cash flows from operations or borrowings under our Revolving Credit Facility. We typically enter into commodity derivative transactions covering a substantial, but varying, portion of our anticipated future oil and gas production for the next 12 to 24 months. A minimum level of derivative coverage is required by certain debt covenants. See Part II. Item 7A. Quantitative and Qualitative Disclosures about Market Risk.
One of the primary sources of variability in our cash provided by operating activities is commodity price volatility, which we partially mitigate through the use of commodity derivative contracts. As of December 31, 2023, we had oil swaps covering 1,374,998 Bbls at a weighted average price of $78.95 per Bbl for calendar 2024 and oil swaps covering the sale of 180,000 Bbls at a weighted average price of $75.30 per Bbl for calendar 2025. As of December 31, 2023, we had no natural gas derivative contracts. For more information on our outstanding derivatives, see Notes to Consolidated Financial Statements—Note 6—Derivative Instruments.
Cash used in investing activities during the years ended December 31, 2023 and 2022 was $120.7 million and $84.6 million, respectively, as compared to $43.3 million during the year ended November 30, 2021 and $4.0 million during the month ended December 31, 2021. Cash used in investing activities primarily relates to capital expenditures for acquisition and development costs. The reduced level of cash used in investing activities in 2021 was primarily attributable to reduced development activity by our operators due to the COVID-19 pandemic, while increased activity during the years ended December 31, 2023 and December 31, 2022 represent a recovery from these same factors. Our cash used in investing activities reflects actual cash spending, which can lag several months from when the related costs were accrued. As a result, our actual cash spending is not always reflective of current levels of development activity. Acquisition and development activities are discretionary. We monitor our capital expenditures on a regular basis, adjusting the amount up or down, and between projects, depending on projected commodity prices, cash flows and financial returns. We supplement development activity on our asset base with opportunistic acquisitions of near-term drilling opportunities when development activity by our operators on our existing properties does not meet our development objectives. Our cash spending for acquisition activities was $35.7 million, $28.5 million and $6.2 million during the fiscal years ended December 31, 2023, December 31, 2022, and November 30, 2021, respectively, and $0.1 million in the month ended December 31, 2021.
Cash used in financing activities was $30.7 million, $57.8 million, and $42.6 million during the fiscal years ended December 31, 2023, December 31, 2022, and November 30, 2021, respectively, and $6.0 million during the month ended December 31, 2021. The cash used in financing activities during the fiscal years ended December 31, 2022 and November 30, 2021 was related to $20.0 million and $30.5 million, respectively, of net repayments under our Prior Revolving Credit Facility as compared to net borrowings of $28.0 million during the fiscal year ended December 31, 2023 under our Revolving Credit Facility. Additionally, we paid distributions to our equity holders of $58.0 million, $36.0 million and $12.0 million during the fiscal years ended December 31, 2023, December 31, 2022, November 30, 2021, respectively, and $6.0 million during the month ended December 31, 2021.
Prior Revolving Credit Facility. See Notes to the Consolidated Financial Statements —Note 5—Credit Facility for further details regarding the Prior Revolving Credit Facility.
Revolving Credit Facility. In connection with the Spin-Off, we entered into the secured Revolving Credit Facility. The Revolving Credit Facility amends and restates the Prior Revolving Credit Facility.
The Predecessor, as predecessor borrower under the Prior Revolving Credit Facility, assigned the liens and its existing rights, liabilities and obligations under the Prior Revolving Credit Facility to Vitesse. Vitesse then entered into the Revolving Credit Facility with Wells Fargo Bank, N.A., as administrative agent, and a syndicate of banks, as lenders. The Revolving Credit Facility will mature on April 29, 2026.
Under the Revolving Credit Facility, we are permitted to make cash distributions without limit to our equity holders if (i) no event of default or borrowing base deficiency (i.e., outstanding debt (including loans and letters of credit) exceeds the borrowing base) then exists or would result from such distribution and (ii) after giving effect to such distribution, (a) our total outstanding credit usage does not exceed 80% of the least of (the following collectively referred to as “Commitments”): (1) $500 million, (2) our then-effective borrowing base, and (3) the then-effective aggregate amount of the aggregate elected commitments and (b) as of the date of such distribution, the EBITDAX Ratio does not exceed 1.50 to 1.00. If our EBITDAX Ratio does not exceed 2.25 to 1.00, and if our total outstanding credit usage does not exceed 80% of the Commitments, we may also make distributions if our free cash flow (as defined under the Revolving Credit Facility) is greater than $0 and we have delivered a certificate to our lenders attesting to the foregoing.
As of December 31, 2023, the Company’s borrowing base was $245.0 million with an aggregate elected commitment of $180.0 million of which $81.0 million was outstanding. On January 17, 2024, the Company increased the elected commitments to
65
Table of Contents
$210 million and added a fifth lender to the syndicate of banks. See Notes to Consolidated Financial Statements—Note 5—Credit Facility for further details regarding the Revolving Credit Facility.
Material Cash Requirements. Our material short-term cash requirements include payments under our short-term lease agreements, recurring payroll and benefits obligations for our employees, capital and operating expenditures and other working capital needs. As commodity prices improve, our working capital requirements may increase as we spend additional capital, increase production and pay larger settlements on our outstanding commodity derivative contracts.
Our long-term material cash requirements from currently known obligations include settlements on our outstanding commodity derivative contracts, future obligations to plug, abandon and remediate our oil and gas properties at the end of their productive lives, and operating lease obligations. We cannot provide specific timing for repayments of outstanding borrowings on our Revolving Credit Facility, or the associated interest payments, as the timing and amount of borrowings and repayments cannot be forecasted with certainty and are based on working capital requirements, commodity prices and acquisition and divestiture activity, among other factors. We cannot provide specific timing for other current and long-term liability obligations where we cannot forecast with certainty the amount and timing of such payments, including asset retirement obligations, as the plugging and abandonment of wells is at the discretion of the operators and any amounts we may be obligated to pay under our derivative contracts, as such payments are dependent on commodity prices in effect at the time of settlement. See Notes to Consolidated Financial Statements—Note 4— Fair Value Measurements for further information on these contracts and their fair values as of December 31, 2023, which fair values represent the estimated cash settlement amount required to terminate such instruments based on forward price curves for commodities as of that date.
Dividends. We paid cash dividends to our equity holders of $58.0 million during the year ended December 31, 2023. While we believe that our future cash flows from operations will be able to sustain the current level of dividends, future dividends may change based on a variety of factors, including contractual restrictions, legal limitations (the most common of which are limitations set forth in a company’s organizational documents and insolvency), business developments and the judgment of our Board. Future cash dividends to equity holders are subject to the terms of the Revolving Credit Facility, as previously described. There can be no guarantee that we will be able to pay dividends at current levels or at all or otherwise return capital to our investors in the future.
Capital Expenditures. For the year ended December 31, 2023 total capital expenditures was $120.5 million, including development expenditures and our acquisition activity. We expect to fund future capital expenditures with cash generated from operations and, if required, borrowings under our Revolving Credit Facility. The foregoing excludes larger acquisitions, which are typically not included in our annual capital expenditures budget. With our cash on hand, cash flow from operations, and borrowing capacity under our Revolving Credit Facility, we believe that we will have sufficient cash flow and liquidity to fund our budgeted capital expenditures and operating expenses for at least the next twelve months. However, we may seek additional access to capital and liquidity including issuing equity or debt securities and extending maturities. We cannot assure you, however, that any additional capital will be available to us on favorable terms or at all. Our capital expenditures could be curtailed if our cash flows decline or we are otherwise unable to access capital or liquidity. Reductions of capital expenditures used to drill and complete new oil and natural gas wells would likely result in lower levels of oil and natural gas production in the future. Our future success in growing proved reserves and production may be dependent on our ability to access outside sources of capital.
The amount, timing and allocation of capital expenditures are largely discretionary and subject to change based on a variety of factors. If oil and natural gas prices decline below our acceptable levels, or costs increase, we may choose to defer a portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected financial returns and potential to generate near-term cash flow. We may also increase our capital expenditures significantly to take advantage of opportunities we consider to be attractive. We will carefully monitor and may adjust our projected capital expenditures in response to success or lack of success in drilling activities, changes in prices, availability of financing and joint venture opportunities, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, change in service costs, contractual obligations, internally generated cash flow and other factors both within and outside our control. For additional information on the impact of changing prices and market conditions on our financial position, see Part II. Item 7A Quantitative and Qualitative Disclosures About Market Risk.
Effects of Inflation and Pricing. The oil and natural gas industry is cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry put pressure on the economic stability and pricing structure within the industry. Higher prices for oil and natural gas could result in increases in the costs of materials, services and personnel, which we have seen in 2023 and 2022 compared to 2021. Typically, as prices for oil and natural gas increase, so do all associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion. Material changes in prices also impact our revenue stream, estimates of future reserves, borrowing base calculations of bank loans, impairment assessments of oil and natural gas properties, and values of properties in purchase and sale transactions. Such changes can impact the value of oil and natural gas companies and their ability to raise capital, borrow money and retain
66
Table of Contents
personnel. Despite these effects of inflation and pricing, we expect to continue generating significant amounts of free cash flow at current commodity price levels.
Non-GAAP Financial Information
Reconciliation of PV-10 to Standardized Measure
PV-10 is derived from the Standardized Measure, which is the most directly comparable GAAP financial measure for proved reserves. PV-10 is a computation of the Standardized Measure on a pre-tax basis. PV-10 is equal to the Standardized Measure at the applicable date, before deducting future income taxes, discounted at ten percent. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated proved reserves prior to taking into account future income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. PV-10, however, is not a substitute for the Standardized Measure. PV-10 and the Standardized Measure do not purport to represent the fair value of our oil and natural gas reserves.
The table below reconciles the pre-tax PV-10 value of our proved reserves at SEC prices as of December 31, 2023 to the Standardized Measure.
| FOR THE YEAR ENDED DECEMBER 31, | ||
|---|---|---|
| (in thousands) | 2023 | |
| Pre-Tax Present Value of Estimated Future Net Revenues (Pre-Tax PV10%) | $ | 682,070 |
| Future Income Taxes, Discounted at 10% | $ | (106,379) |
| Standardized Measure of Discounted Future Net Cash Flows | $ | 575,691 |
Uncertainties are inherent in estimating quantities of proved reserves, including many risk factors beyond our control. Reserve engineering is a subjective process of estimating subsurface accumulations of oil and natural gas that cannot be measured in an exact manner. As a result, estimates of proved reserves may vary depending upon the engineer estimating the reserves. Further, our actual realized price for our oil and natural gas is not likely to equal the pricing parameters used to calculate our proved reserves. As such, the oil and natural gas quantities and the value of those commodities ultimately recovered from our properties will vary from reserve estimates.
Additional discussion of our proved reserves is set forth under Notes to Consolidated Financial Statements—Supplemental Oil and Gas Information (Unaudited).
Critical Accounting Policies and Estimates
We prepare our financial statements and the accompanying notes in conformity with accounting principles generally accepted in the United States, which require management to make estimates and assumptions about future events that affect the reported amounts in the financial statements and the accompanying notes. We identify certain accounting policies and estimates as critical based on, among other things, their impact on our financial condition, results of operations, and the degree of difficulty, subjectivity and complexity in their application. Critical accounting policies and estimates cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. Management routinely discusses the development, selection and disclosure of each of the critical accounting policies and estimates. The following is a discussion of our most critical accounting policies and estimates.
Proved Oil and Natural Gas Reserves
The determination of depreciation, depletion and amortization expense as well as impairments that may be recognized on our oil and natural gas properties are highly dependent on the estimates of the proved oil and natural gas reserves attributable to our properties. Our estimate of proved reserves is based on the quantities of oil and natural gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in the future years from known reservoirs under existing economic and operating conditions. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. For example, we must estimate the amount and timing of future operating costs, production taxes and development costs, all of which may in fact vary considerably from actual results. In addition, as the prices of oil and natural gas and cost levels change from year to year, the economics of producing our reserves may change and therefore the estimate of proved reserves may also change. Approximately 30% of our proved oil and gas reserve volumes are categorized as proved undeveloped reserves. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves, future cash flows from our reserves, and future development of our proved undeveloped reserves. Our proved oil and gas reserve information was computed by applying the average first-day-of-the- month oil and gas price during the 12-month period ended on the balance sheet date.
67
Table of Contents
External petroleum engineers independently estimated all of the proved reserve quantities included in our financial statements for the year ended December 31, 2023, which were prepared in accordance with the rules promulgated by the SEC. In connection with our external petroleum engineers performing their independent reserve estimations, we furnish them with the following information: (1) technical support data, (2) technical analysis of geologic and engineering support information, (3) economic and production data and (4) our well ownership interests.
Oil and Natural Gas Properties
We follow the successful efforts method of accounting for oil and gas activities. Under this method of accounting, costs associated with the acquisition, drilling, and equipping of successful exploratory wells and costs of successful and unsuccessful development wells are capitalized and depleted, net of estimated salvage values, using the units-of-production method on the basis of a reasonable aggregation of properties within a common geological structural feature or stratigraphic condition, such as a reservoir or field.
We review our oil and natural gas properties for impairment whenever events and circumstances indicate a decline in the recoverability of their carrying value. If we determined an evaluation for impairment is required, we estimate the expected future cash flows of our oil and natural gas properties and compare such cash flows to the carrying amount of the proved oil and natural gas properties to determine if the amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying value of proved oil and natural gas properties to estimated fair value. The factors used to estimate fair value include estimates of reserves, future commodity prices adjusted for basis differentials, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the projected cash flows. The discount rate is a rate that management believes is representative of current market conditions and includes estimates for a risk premium and other operational risks.
For the years ended December 31, 2023, December 31, 2022, and November 30, 2021 and the month ended December 31, 2021 we did not record any impairment expense.
Equity-Based Compensation
The Company recognizes equity-based compensation expense associated with its long-term incentive plan (“LTIP”) awards using the straight-line method over the requisite service period, which is generally the vesting period of the award except when provisions are present that accelerate vesting, based on their grant date fair values. The Company has elected to account for forfeitures of equity awards as they occur.
Previous grants of 180,875 RSUs were forfeited during the year ended December 31, 2023. In January 2024, 792,000 restricted stock units vested with the Company retaining 332,840 of the vested shares to fund employee tax withholding of $6.9 million with the retained shares subsequently retired by the Company.
Predecessor Equity-Based Compensation
In 2020, the Predecessor amended the Predecessor Company Agreement which modified certain terms and conditions related to management incentive units (“MIUs”) and common units held by the founding members of management. The Predecessor accounted for MIUs granted to employees (which excludes the founding members of management) as liability awards under accounting guidance related to share-based compensation, whereby vested awards are recognized as liabilities, with changes in the estimated value of the awards recorded in earnings, until the holders have borne the risk of unit ownership, at which point the liability associated with the employee MIUs is reclassified to temporary equity, and changes in the estimated value of the MIUs are recorded as an adjustment to members’ equity.
Equity-based compensation was also recognized for in-substance call options granted to the founding members of management which were classified as liabilities, recorded at estimated fair market value at each period end. Changes in the estimated fair value were recorded in earnings. As the Predecessor was a private entity whose units were not traded, we considered the average volatility of comparable entities to develop an estimate of expected volatility which resulted in a reasonable estimate of fair value.
Recently Issued or Adopted Accounting Pronouncements
For discussion of recently issued or adopted accounting pronouncements, see Notes to the Consolidated Financial Statements—Note 2—Significant Accounting Policies.”
Off Balance Sheet Arrangements
We currently do not have any off-balance sheet arrangements that have or are reasonably likely to have a material current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.
68
Table of Contents