VTS 10-Q
Vitesse Energy, Inc. (VTS)
10-Q
2023-07-31
For: 2023-06-30
View Original
Added on
April 12, 2026
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |||||
For the quarterly period ended June 30, 2023
OR
| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |||||
For the transition period from ______ to ______
Commission file number 001-41546
(Exact name of registrant as specified in its charter)
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | ||||
| (Address of Principal Executive Offices) | (Zip Code) | ||||
Registrant's telephone number, including area code
N/A
(Former name, former address and former fiscal year, if changed since last report)
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Trading Symbol(s) | Name of each exchange on which registered | ||||||
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports); and (2) has been subject to such filing requirements for the past 90 days. Yes x No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
| Large accelerated filer | o | Accelerated filer | o | ||||||||
| x | Smaller reporting company | ||||||||||
| Emerging growth company | |||||||||||
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No x
The registrant had outstanding 28,787,388 shares of common stock as of July 28, 2023.
TABLE OF CONTENTS
| Page | ||||||||
3
CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS
The information in this Form 10-Q contains statements which, to the extent they are not statements of historical or present fact, constitute “forward-looking statements” under the securities laws. These forward-looking statements are intended to provide management’s current expectations or plans for our future operating and financial performance, based on assumptions currently believed to be valid. Forward-looking statements can be identified by the use of words such as “believe,” “expect,” “expectations,” “plans,” “strategy,” “prospects,” “estimate,” “project,” “target,” “anticipate,” “will,” “should,” “see,” “guidance,” “outlook,” “confident” and other words of similar meaning in connection with a discussion of future operating or financial performance. Forward-looking statements may include, among other things, statements relating to future earnings, cash flow, results of operations, uses of cash, tax rates and other measures of financial performance or potential future plans, strategies or transactions of Vitesse, and other statements that are not historical facts. Forward-looking statements are not guarantees of future results and conditions, but rather are subject to numerous assumptions, risks, and uncertainties that may cause actual future results to be materially different from those contemplated, projected, estimated, or budgeted. Such assumptions, risks, uncertainties and other factors include, but are not limited to, the following:
■the timing and extent of changes in oil and natural gas prices;
■our ability to successfully implement our business plan;
■the pace of our operators’ drilling and completion activity on our properties, including in connection with refrac campaigns and extended length three-mile lateral infills;
■our operators’ ability to complete projects on time and on budget;
■uncertainties about estimates of reserves, identification of drilling locations and the ability to add reserves in the future;
■our ability to complete acquisitions;
■actions taken by third-party operators, processors, transporters and gatherers;
■natural disasters, adverse weather conditions, war (such as the ongoing military conflict in Ukraine), financial or political instability, casualty losses and other matters beyond our control;
■the impact of the COVID-19 pandemic and the measures implemented to contain it;
■changes in general economic conditions, including central bank policy actions, bank failures and associated liquidity risks;
■our ability to achieve the benefits that we expect to achieve as an independent publicly traded company;
■the qualification of the Distribution and certain related transactions as tax-free under the Code;
■inflation;
■infrastructure constraints and related factors affecting our properties;
■competitive conditions in our industry;
■the effects of existing and future laws and governmental regulations;
■the availability and price of oil and natural gas to the consumer compared to the price of alternative and competing fuels;
■operating hazards and other risks incidental to gathering, storing and transporting oil and natural gas;
■restrictions in our Revolving Credit Facility;
■interest rates;
■the effects of ongoing or future litigation;
■cyber-related risks;
■changes in insurance markets impacting costs and the level and types of coverage available;
■climate change and the physical and financial risks associated with fluctuating regional and global weather conditions or patterns;
■energy efficiency and technology trends;
■competition from the same and alternative energy sources;
■changes in the availability and cost of capital;
■large customer defaults;
■labor relations; and
■changes in tax status.
The above list of factors is not exhaustive. For additional information on identifying factors that may cause actual results to vary materially from those stated in forward-looking statements, see the discussion under the section Part I, Item 1A. Risk Factors in this Form 10-Q and Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2022, filed with the SEC on February 16, 2023. Any forward-looking statements, express or implied, included in this Form 10-Q are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. Any forward-looking statement that we make in this Form 10-Q speaks only as of the date on which it was made. Except as otherwise required by applicable law, we expressly disclaim any obligation to, update or alter our forward-looking statements, whether as a result of new information, subsequent events or otherwise.
4
GLOSSARY
In this Form 10-Q, unless the context otherwise requires:
■“Amended and Restated Bylaws” refers to the bylaws of Vitesse effective as of January 13, 2023;
■“Amended and Restated Certificate of Incorporation” refers to the certificate of incorporation of Vitesse effective as of January 12, 2023;
■“Basin” refers to a large natural depression on the earth’s surface in which sediments generally brought by water accumulate;
■the “Board” refers to our board of directors;
■“Bbl” refers to one stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to oil, condensate or NGLs;
■“Boe” refers to barrels of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil;
■“Boe/d” refers to one Boe per day;
■“Btu” refers to a British thermal unit, which is the quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit;
■“completion” refers to the process of preparing an oil and natural gas wellbore for production through the installation of permanent production equipment, as well as perforation and fracture stimulation to optimize production of oil, natural gas and/or NGLs;
■“Code” refers to the United States Internal Revenue Code of 1986, as amended;
■“condensate” refers to a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature;
■“differential” refers to an adjustment to the price of oil or natural gas from an established index price to reflect differences in the quality and/or location of oil or natural gas;
■the “Distribution” refers to the transaction on January 13, 2023 in which Jefferies distributed to its shareholders outstanding shares of our common stock held by Jefferies;
■the “Distribution Date” refers to the date on which the Distribution occurred;
■“dry hole” refers to a well found to be incapable of producing oil and natural gas in sufficient quantities to justify completion;
■“Exchange Act” refers to the Securities Exchange Act of 1934;
■“GAAP” refers to accounting principles generally accepted in the United States;
■“gross acres” refers to the total acres in which a working interest is owned;
■“gross wells” refers to the total wells in which a working interest is owned;
■“IRS” refers to the Internal Revenue Service;
■“Jefferies” or “JFG” refers to Jefferies Financial Group Inc. and its consolidated subsidiaries other than, for all periods following the Spin-Off, Vitesse, unless the context requires otherwise;
■“MBbls” refers to one thousand barrels of oil or NGLs;
■“MBoe” refers to one thousand barrels of oil equivalent;
■“Mcf” refers to one thousand cubic feet of natural gas;
■“MMBoe” refers to one million barrels of oil equivalent;
■“MMBtu” refers to one million British thermal units;
■“MMcf” refers to one million cubic feet of natural gas;
■“net acres” refers to the sum of the fractional working interests owned in gross acres (e.g., a 10% working interest in a lease covering 1,280 gross acres is equivalent to 128 net acres);
■“net wells” refers to wells that are deemed to exist when the sum of fractional ownership working interests in gross wells equals one;
■“NGLs” refer to natural gas liquids;
■“NYMEX” refers to the New York Mercantile Exchange;
■“NYSE” refers to the New York Stock Exchange;
■“OPEC” refers to the Organization of Petroleum Exporting Countries;
■“PDP” or “proved developed producing” refers to proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods;
■“PDNP” or “proved developed non-producing” refers to proved reserves that are developed behind pipe and are expected to be recovered from zones in existing wells that will require additional completion work or future recompletion prior to the start of production;
■“possible reserves” refers to the additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than probable reserves;
5
■“Pre-Spin-Off Transactions” refers to the series of transactions, including Vitesse’s acquisitions of Vitesse Energy and Vitesse Oil, consummated immediately prior to the Distribution;
■“Prior Revolving Credit Facility” refers to Vitesse Energy’s Amended and Restated Credit Agreement, dated as of April 29, 2022, as amended from time to time, among Vitesse Energy, as borrower, Wells Fargo Bank, N.A., as administrative agent, and the lenders party thereto;
■“probable reserves” refers to the additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered;
■“productive well” refers to a well that is found to be capable of producing oil and natural gas in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes;
■“proved developed reserves” refers to proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of new equipment or operating methods is relatively minor compared to the cost of a new well;
■“proved reserves” refers to the quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time;
■“PUD” or “proved undeveloped” refers to proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for development. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years from the date that such undrilled location was initially classified as proved undeveloped unless specific circumstances justify a longer time. Under no circumstances shall estimates of proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty:
■“reserves” refers to estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project;
■“Revolving Credit Facility” refers to Vitesse’s Second Amended and Restated Credit Agreement, as amended from time to time, among Vitesse, as borrower, Wells Fargo Bank, N.A., as administrative agent, and the lenders party thereto, dated as of January 13, 2023;
■“SEC” refers to the Securities and Exchange Commission;
■“Securities Act” refers to Securities Act of 1933;
■“SOFR” refers to the Secured Overnight Financing Rate;
■the “Spin-Off” refers to our separation on January 13, 2023 from Jefferies and the creation of an independent, publicly traded company, Vitesse, through (1) the Pre-Spin-Off Transactions and (2) the Distribution;
■“Standardized Measure” refers to discounted future net cash flows estimated by applying year-end SEC prices (based on the 12-month unweighted arithmetic average of the first-day-of-the-month oil and natural gas prices for such year-end period) to the estimated future production of year-end proved reserves. Future cash flows are reduced by estimated future production and development costs, including asset retirement obligations, based on year-end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash flows over our tax basis in the oil and natural gas properties. Future net cash flows after income taxes are discounted using a 10% annual discount rate;
■“Stock Repurchase Program” refers to the stock repurchase program approved by the Board in February 2023 authorizing the repurchase of up to $60 million of the Company’s common stock;
■ “Tax Matters Agreement” refers to the tax matters agreement entered into between Jefferies and the Company on January 13, 2023;
■“Treasury Regulations” refers to final, temporary, and (to the extent they can be relied upon) proposed regulations promulgated under the Code, as amended from time to time (including corresponding provisions and succeeding provisions);
■“Two-stream basis” refers to the reporting of production or reserve volumes of oil and wet natural gas, where the NGLs have not been removed from the natural gas stream, and the economic value of the NGLs is included in the wellhead natural gas price;
6
■“Vitesse,” “we,” “our,” “us” and the “Company” (1) when used in regard to events prior to January 13, 2023, refer to Vitesse Energy and do not give effect to the consummation of the Pre-Spin-Off Transactions, and (2) when used in regard to events subsequent to the Spin-Off or future tense, refer to Vitesse Energy, Inc. and its consolidated subsidiaries and give effect to the consummation of the Pre-Spin-Off Transactions, in each case unless the context requires otherwise;
■“Vitesse Energy” refers to Vitesse Energy, LLC and its consolidated subsidiaries;
■“Vitesse Energy Finance” refers to Vitesse Energy Finance LLC, the holder of a majority of the equity interests in Vitesse Energy prior to the Pre-Spin-Off Transactions and an indirect wholly owned subsidiary of Jefferies;
■“Vitesse Oil” refers to Vitesse Oil, LLC;
■“Vitesse Oil Revolving Credit Facility” refers to Vitesse Oil’s Credit Agreement, dated as of July 23, 2015, as amended from time to time, among Vitesse Oil, as borrower, Wells Fargo Bank, N.A., as administrative agent, and the lenders party thereto; and
■“WTI” refers to West Texas Intermediate.
7
PRESENTATION OF FINANCIAL AND OPERATING DATA
Unless otherwise indicated, the financial, reserve and operation information presented for periods prior to the January 13, 2023 Spin-Off in this Form 10-Q is that of our Predecessor, Vitesse Energy. Also, unless otherwise indicated all references to wells, working interest, royalty interest, or acreage are based on the published information available as of the date indicated, which may not be current.
INDUSTRY AND MARKET DATA
This Form 10-Q includes information concerning our industry and the markets in which we operate that is based on information from public filings, internal company sources, various third-party sources and management estimates. Management’s estimates regarding Vitesse’s position, share and industry size are derived from publicly available information and our internal research, and are based on assumptions we made upon reviewing such data and our knowledge of such industry and markets, which we believe to be reasonable. While we are not aware of any misstatements regarding any industry data presented in this Form 10-Q and believe such data to be accurate, we have not independently verified any data obtained from third-party sources and cannot assure you of the accuracy or completeness of such data. Such data may involve uncertainties and is subject to change based on various factors, including those discussed in the section entitled “Part II, Item 1A, Risk Factors.”
8
PART I – FINANCIAL INFORMATION
Item 1. Financial Statements
VITESSE ENERGY, INC.
Condensed Consolidated Balance Sheets (Unaudited)
| JUNE 30, | DECEMBER 31, | ||||||||||
| (in thousands, except shares and units) | 2023 | 2022 | |||||||||
| Assets | |||||||||||
| Current Assets | |||||||||||
| Cash | $ | $ | |||||||||
| Revenue receivable | |||||||||||
| Commodity derivatives (Note 6) | |||||||||||
| Prepaid expenses and other current assets | |||||||||||
| Total current assets | |||||||||||
| Oil and Gas Properties-Using the successful efforts method of accounting (Note 2) | |||||||||||
| Proved oil and gas properties | |||||||||||
| Less accumulated DD&A and impairment | ( | ( | |||||||||
| Total oil and gas properties | |||||||||||
| Other Property and Equipment—Net | |||||||||||
| Other Assets | |||||||||||
| Commodity derivatives (Note 6) | |||||||||||
| Other noncurrent assets | |||||||||||
| Total other assets | |||||||||||
| Total assets | $ | $ | |||||||||
| Liabilities, Redeemable Units and Equity | |||||||||||
| Current Liabilities | |||||||||||
| Accounts payable | $ | $ | |||||||||
| Accrued liabilities (Note 7) | |||||||||||
| Commodity derivatives (Note 6) | |||||||||||
| Other current liabilities | |||||||||||
| Total current liabilities | |||||||||||
| Long-term Liabilities | |||||||||||
| Revolving credit facility (Note 5) | |||||||||||
| Deferred tax liability (Note 11) | |||||||||||
| Asset retirement obligations | |||||||||||
| Other noncurrent liabilities | |||||||||||
| Total liabilities | $ | $ | |||||||||
| Commitments and Contingencies (Note 9) | |||||||||||
| Predecessor Redeemable Management Incentive Units (Note 10) | — | ||||||||||
| Equity (Note 10) | |||||||||||
Preferred stock, $ | — | ||||||||||
Common stock, $ | — | ||||||||||
| Additional paid-in capital | — | ||||||||||
| Accumulated deficit | ( | — | |||||||||
Predecessor members' equity-common units- | — | ||||||||||
| Total equity | |||||||||||
| Total liabilities, redeemable units and equity | $ | $ | |||||||||
See notes to condensed consolidated financial statements
9
VITESSE ENERGY, INC.
Condensed Consolidated Statements of Operations (Unaudited)
| FOR THE THREE MONTHS ENDED | FOR THE SIX MONTHS ENDED | ||||||||||||||||||||||
| JUNE 30, | JUNE 30, | ||||||||||||||||||||||
| (In thousands, except share and unit data) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Revenue | |||||||||||||||||||||||
| Oil | $ | $ | $ | $ | |||||||||||||||||||
| Natural gas | |||||||||||||||||||||||
| Total revenue | |||||||||||||||||||||||
| Operating Expenses | |||||||||||||||||||||||
| Lease operating expense | |||||||||||||||||||||||
| Production taxes | |||||||||||||||||||||||
| General and administrative | |||||||||||||||||||||||
| Depletion, depreciation, amortization, and accretion | |||||||||||||||||||||||
| Equity-based compensation (Note 10) | |||||||||||||||||||||||
| Total operating expenses | |||||||||||||||||||||||
| Operating Income (Loss) | ( | ||||||||||||||||||||||
| Other (Expense) Income | |||||||||||||||||||||||
| Commodity derivative gain (loss), net | ( | ( | |||||||||||||||||||||
| Interest expense | ( | ( | ( | ( | |||||||||||||||||||
| Other income | |||||||||||||||||||||||
| Total other (expense) income | ( | ( | |||||||||||||||||||||
| Income Before Income Taxes | $ | $ | $ | $ | |||||||||||||||||||
| Provision for Income Taxes | ( | ( | |||||||||||||||||||||
| Net Income (Loss) | $ | $ | $ | ( | $ | ||||||||||||||||||
| Net income attributable to Predecessor common unit holders | |||||||||||||||||||||||
| Net Income (Loss) Attributable to Vitesse Energy, Inc. | $ | $ | $ | ( | $ | ||||||||||||||||||
EPS (See Note 10) | |||||||||||||||||||||||
| Weighted average common shares / Predecessor common unit outstanding – basic | |||||||||||||||||||||||
| Weighted average common shares / Predecessor common unit outstanding – diluted | |||||||||||||||||||||||
| Net income (loss) per common share / Predecessor common unit – basic | $ | $ | $ | ( | $ | ||||||||||||||||||
| Net income (loss) per common share / Predecessor common unit – diluted | $ | $ | $ | ( | $ | ||||||||||||||||||
| Net loss per Predecessor non-founder MIUs classified as temporary equity–basic and diluted | $ | $ | |||||||||||||||||||||
See notes to condensed consolidated financial statements
10
VITESSE ENERGY, INC.
Condensed Consolidated Statements of Equity (Unaudited)
| Common Stock | Preferred Stock | ||||||||||||||||||||||||||||||||||||||||||||||
| (In thousands, except share data) | Shares | Amount | Shares | Amount | Additional Paid-In Capital | Predecessor Members' Equity | Accumulated Deficit | Total Equity | |||||||||||||||||||||||||||||||||||||||
| Balance—January 1, 2023 | — | $ | — | — | $ | — | $ | — | $ | $ | — | $ | |||||||||||||||||||||||||||||||||||
| Net income (loss) | — | — | — | — | — | ( | ( | ||||||||||||||||||||||||||||||||||||||||
| Issuance of common stock in exchange for Vitesse Energy, LLC | — | — | ( | — | — | ||||||||||||||||||||||||||||||||||||||||||
| Issuance of common stock in exchange for Non-Founder MIU's | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||
| Acquisition of Vitesse Oil, LLC | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||
| Issuance of restricted stock units | — | — | ( | — | — | — | |||||||||||||||||||||||||||||||||||||||||
| Issuance of Transitional Plan awards | — | — | ( | — | — | — | |||||||||||||||||||||||||||||||||||||||||
| Equity-based compensation | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||
| Common stock dividends declared | — | — | — | — | ( | — | — | ( | |||||||||||||||||||||||||||||||||||||||
| Repurchase of common stock | ( | — | — | — | ( | — | — | ( | |||||||||||||||||||||||||||||||||||||||
| Balance—March 31, 2023 | $ | — | $ | — | $ | $ | — | $ | ( | $ | |||||||||||||||||||||||||||||||||||||
| Net income | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||
| Issuance of restricted stock units | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||
| Equity-based compensation | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||
| Common stock dividends declared | — | — | — | — | ( | — | — | ( | |||||||||||||||||||||||||||||||||||||||
| Balance—June 30, 2023 | $ | — | $ | — | $ | $ | — | $ | ( | $ | |||||||||||||||||||||||||||||||||||||
See notes to condensed consolidated financial statements
11
VITESSE ENERGY, INC.
Condensed Consolidated Statements of Equity (Unaudited)
| Common Stock | Preferred Stock | ||||||||||||||||||||||||||||||||||||||||||||||
| (In thousands, except share data) | Shares | Amount | Shares | Amount | Additional Paid-In Capital | Predecessor Members' Equity | Accumulated Deficit | Total Equity | |||||||||||||||||||||||||||||||||||||||
| Balance—January 1, 2022 | — | $ | — | — | $ | — | $ | — | $ | $ | — | $ | |||||||||||||||||||||||||||||||||||
| Net loss | — | — | — | — | — | ( | — | ( | |||||||||||||||||||||||||||||||||||||||
| Distribution to common unit holders | — | — | — | — | — | ( | — | ( | |||||||||||||||||||||||||||||||||||||||
| Fair market value MIU adjustment (Note 10) | — | — | — | — | — | ( | — | ( | |||||||||||||||||||||||||||||||||||||||
| Balance—March 31, 2022 | — | $ | — | $ | — | $ | — | $ | — | $ | $ | — | $ | ||||||||||||||||||||||||||||||||||
| Net income | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||
| Distribution to common unit holders | — | — | — | — | — | ( | — | ( | |||||||||||||||||||||||||||||||||||||||
| Fair market value MIU adjustment (Note 10) | — | — | — | — | — | ( | — | ( | |||||||||||||||||||||||||||||||||||||||
| Balance—June 30, 2022 | — | $ | — | — | $ | — | $ | — | $ | $ | — | $ | |||||||||||||||||||||||||||||||||||
See notes to condensed consolidated financial statements
12
VITESSE ENERGY, INC.
Condensed Consolidated Statements of Cash Flows (Unaudited)
| FOR THE SIX MONTHS ENDED | |||||||||||
| JUNE 30, | |||||||||||
| (in thousands) | 2023 | 2022 | |||||||||
| Cash Flows from Operating Activities | |||||||||||
| Net income (loss) | $ | ( | $ | ||||||||
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||||||||||
| Depletion, depreciation, amortization, and accretion | |||||||||||
| Unrealized loss (gain) on derivative instruments | ( | ||||||||||
| Equity-based compensation | |||||||||||
| Deferred income taxes | |||||||||||
| Amortization of debt issuance costs | |||||||||||
| Changes in operating assets and liabilities that provided (used) cash: | |||||||||||
| Revenue receivable | ( | ||||||||||
| Prepaid expenses and other current assets | ( | ( | |||||||||
| Accounts payable | ( | ||||||||||
| Accrued liabilities | ( | ||||||||||
| Other | ( | ||||||||||
| Net cash provided by Operating Activities | $ | $ | |||||||||
| Cash Flows from Investing Activities | |||||||||||
| Acquisition of oil and gas properties | ( | ( | |||||||||
| Development of oil and gas properties | ( | ( | |||||||||
| Purchase of property and equipment | ( | ( | |||||||||
| Net cash used in Investing Activities | ( | ( | |||||||||
| Cash Flows from Financing Activities | |||||||||||
| Proceeds from revolving credit facility | |||||||||||
| Repayments of revolving credit facility | ( | ||||||||||
| Repayments of Vitesse Oil revolving credit facility | ( | ||||||||||
| Dividends/distributions paid | ( | ( | |||||||||
| Repurchases of common stock | ( | ||||||||||
| Debt issuance costs | ( | ( | |||||||||
| Net cash used in Financing Activities | ( | ( | |||||||||
| Net Increase (Decrease) in Cash | ( | ||||||||||
Cash—Beginning of period | |||||||||||
Cash—End of period | $ | $ | |||||||||
| Supplemental Disclosure of Cash Flow Information | |||||||||||
| Cash paid for interest | $ | $ | |||||||||
| Cash paid for income taxes | |||||||||||
| Supplemental Disclosure of Noncash Activity | |||||||||||
| Oil and gas properties included in accounts payable and accrued liabilities | $ | $ | |||||||||
| Asset retirement obligations capitalized to oil and gas properties | |||||||||||
| Issuance of common stock to acquire Vitesse Oil | |||||||||||
See notes to condensed consolidated financial statements
13
VITESSE ENERGY, INC.
Notes to the Condensed Consolidated Financial Statements
Note 1—Nature of Business
Vitesse Energy, Inc. (“Vitesse” or the “Company”) was incorporated under the General Corporation Law of the State of Delaware on August 5, 2022 as a wholly owned subsidiary of an affiliate of Jefferies Financial Group Inc. (“JFG”) for the purpose of effecting the Spin-Off of Vitesse Energy, LLC (the “Predecessor”) by JFG. On January 13, 2023, JFG completed the legal and structural separation of the Predecessor from JFG. To effect the separation, first, JFG and Jefferies Capital Partners (“JCP”), among others, undertook certain Pre-Spin-Off Transactions described below:
*Certain members of management of the Predecessor transferred all of their equity interest in the Predecessor to JFG as repayment for loans from affiliates of JFG;
*JFG and other holders of the Predecessor’s equity interests transferred all of their interest in the Predecessor to Vitesse in exchange for newly issued shares of common stock, par value $0.01 per share (“common stock”), of Vitesse;
*Vitesse Oil, LLC ("Vitesse Oil") equity holders transferred their interests in Vitesse Oil to Vitesse in exchange for newly issued shares of Vitesse common stock (the “Vitesse Oil Transaction”);
*Compensation agreements and compensation plans of the Predecessor were eliminated and replaced with new compensation plans of Vitesse, including a long-term incentive plan;
*Vitesse entered into a Revolving Credit Facility, which amended and restated the Predecessor’s credit facility, and used the proceeds to repay in full and terminate the Vitesse Oil Revolving Credit Facility and repay the Predecessor’s credit facility.
*The Predecessor entered into a Separation and Distribution Agreement and Tax Matters Agreement with JFG related to the Spin-Off.
JFG and JCP then distributed the Vitesse outstanding common stock held by each to their respective shareholders, and Vitesse became an independent, publicly traded company. The Company’s common stock began trading on the New York Stock Exchange on January 17, 2023 under the symbol “VTS.”
The issued and outstanding member interests of the Predecessor and Vitesse Oil together represented substantially all of those businesses or investments of JFG and JCP that acquire, develop, manage and monetize non-operated oil and natural gas working, royalty and mineral interests in the United States.
Immediately prior to the completion of the Spin-Off, the Company succeeded to the operations of the Predecessor. As the Predecessor and the Company were under common control, and because the Company was not a substantive entity prior to the Spin-Off, for accounting purposes the Company has succeeded to the operations of the Predecessor. The Vitesse Oil Transaction is accounted for as an asset acquisition by the Company as Vitesse Oil and the Company were not under common control.
The Predecessor is a Delaware limited liability company formed on April 29, 2014. Prior to the Spin-Off, the membership interests in the Predecessor were held approximately 97.5 % by affiliates of JFG and approximately 2.5 % by 3B Energy, LLC (“3B”), an entity whose members are comprised of certain executives of the Company. Financial information presented for periods ended prior to January 13, 2023 is that of the Predecessor, which was organized as a tax partnership. Therefore, for periods prior to January 13, 2023 the financial statements of the Company do not reflect the impact of income taxes. As noted above, as a result of the Spin-Off, the Predecessor became a wholly owned subsidiary of Vitesse, which is organized as a taxable corporation. Therefore, the financial statements of the Company reflect the impact of income taxes applied to the consolidated results of operations of the Company, including the initial basis differences between tax and financial accounting for our assets and liabilities at the Spin-Off resulting in a one time charge of $44.1 million to income tax expense. Financial information presented for periods ended on and after January 13, 2023 is that of the Company, which reflects the combined results of the Predecessor and Vitesse Oil.
The business purpose of the Company is to acquire, own, explore, develop, manage, produce, exploit, and dispose of oil and gas properties. The Company is focused on returning capital to stockholders through owning and acquiring non-operated working interest and royalty interest ownership primarily in the core of the Bakken and Three Forks formations in the Williston Basin of North Dakota and Montana. The Company also owns non-operated interests in oil and gas properties in the Central Rockies, including the Denver-Julesburg Basin and the Powder River Basin.
Note 2—Significant Accounting Policies
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 of our oil and gas properties. 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
14
operators in aggregate. Both methods of determining classification of GT costs are acceptable given that we do not operate any of our oil and gas properties and do not have access to such GT contracts with the customer.
The change represents a change in estimate effected by a change in accounting principle. 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.
Interim Financial Statements
These financial statements in this Quarterly Report on Form 10-Q have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission. Accordingly, these financial statements reflect all adjustments, consisting of normal recurring adjustments, that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective interim periods. Certain information and note disclosures normally included in our annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted from these financial statements pursuant to such rules and regulations, although we believe that the disclosures made are adequate to make the information presented not misleading. Results of operations for the three and six months ended June 30, 2023 are not necessarily indicative of the results that may be expected for the year ending December 31, 2023. These financial statements and other information included in this Quarterly Report on Form 10-Q should be read in conjunction with the 2022 audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2022.
Segment and Geographic Information
The Company operates in a single reportable segment. The Company’s chief operating decision maker is the Chief Executive Officer. All of the Company’s operations are conducted in the continental United States.
Use of Estimates
The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.
Depletion, depreciation, and amortization (“DD&A”) and the evaluation of proved oil and gas properties for impairment are determined using estimates of oil and gas reserves. There are numerous uncertainties in estimating the quantity of reserves and in projecting the future rates of production and timing of development expenditures, which includes lack of control over future development plans as a non-operator. Oil and gas reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way. In addition, significant estimates include, but are not limited to, estimates relating to certain crude oil and natural gas revenues and expenses, fair value of assets acquired and liabilities assumed in business combinations, valuation of Predecessor equity-based compensation, and valuation of commodity derivative instruments. Further, these estimates and other factors, including those outside of the Company’s control, such as the impact of lower commodity prices, may have a significant adverse impact to the Company’s business, financial condition, results of operations and cash flows.
Oil and Gas Properties
The Company follows 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. During the three and six months ended June 30, 2023, the Company recorded depletion expense of $18.6 million, and $36.9 million, respectively. The Company’s depletion rate per Boe for the three and six months ended June 30, 2023 was $17.98 and $17.82 , respectively. During the three and six months ended June 30, 2022, the Company
15
recorded depletion expense of $14.9 million, and $29.0 million, respectively. The Company’s depletion rate per Boe for the three and six months ended June 30, 2022 was $16.65 and $16.45 , respectively.
Exploration, geological and geophysical costs, delay rentals, and drilling costs of unsuccessful exploratory wells are charged to expense as incurred. The sale of a partial interest in a proved property is accounted for as a cost recovery, and no gain or loss is recognized as long as this treatment does not significantly affect the units-of-production amortization rate. A gain or loss is recognized for all other sales of proved properties.
Costs associated with unevaluated exploratory wells are excluded from the depletable base until the determination of proved reserves, at which time those costs are reclassified to proved oil and gas properties and subject to depletion. If it is determined that the exploratory well costs were not successful in establishing proved reserves, such costs are expensed at the time of such determination.
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.
Predecessor Equity-Based Compensation
In 2020, the Predecessor amended its Limited Liability Company Agreement (the “Company Agreement”) which modified certain terms and conditions related to management incentive units (“MIUs”) (see Note 10) 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 employee MIUs are recorded as an adjustment to members’ equity.
Revenue Recognition
The Company’s revenue is derived from the sale of its produced oil and natural gas from wells in which the Company has non-operated revenue or royalty interests. The Company’s oil and natural gas are produced and sold primarily in the core of the Williston Basin in North Dakota and Montana.
The sales of produced oil and natural gas are made under contracts that the operators of the wells have negotiated with customers, which typically include variable consideration based on monthly pricing tied to local indices and volumes delivered. Revenue is recorded at the point in time when control of the produced oil and natural gas transfers to the customer. Statements and payment may not be received via the operator of the wells for one to six months after the date the produced oil and natural gas is delivered, and, as a result, the amount of production delivered to the customer and the price that will be received for the sale of the product is estimated utilizing production reports, market indices, and estimated differentials. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated, and revenue due to the Company is recorded within revenue receivable in the accompanying balance sheets until payment is received. Differences between the estimated amounts and the actual amounts received from the sale of the produced oil and natural gas are recorded when known, which is generally when statements and payment are received. Such differences have historically been immaterial.
For the oil and natural gas produced from wells in which the Company has non-operated revenue or royalty interests, the Company recognizes revenue based on the details included in the statements received from the operator. Any gathering, transportation, processing, production taxes, and other deductions included on the statements are recorded based on the
16
Concentrations of Credit Risk
For the three and six months ended June 30, 2023, three and four operators accounted for 50 percent and 57 percent, respectively, of oil and natural gas revenue.
For the three and six months ended June 30, 2022, three operators accounted for 36 percent and 37 percent, respectively, of oil and natural gas revenue, respectively.
As of June 30, 2023 and December 31, 2022, two and four operators accounted for 43 percent and 65 percent, respectively, of oil and natural gas revenue receivable.
The Company’s oil and natural gas revenue receivable is generated from the sale of oil and natural gas by operators on its behalf. The Company monitors the financial condition of its operators.
Income Taxes
Income taxes are provided for the tax effects of transactions reported in the financial statements and consist of taxes currently payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income tax liabilities represent the future income tax consequences of those differences, which will be taxable when liabilities are settled. Deferred income taxes may also include tax credits and net operating losses that are available to offset future income taxes. Deferred income taxes are measured by applying currently enacted tax rates.
The Company accounts for uncertainty in income taxes for tax positions taken or expected to be taken in a tax return. Only tax positions that meet the more-likely-than-not recognition threshold are recognized. The Company does not have any uncertain tax positions recorded as of June 30, 2023.
The Predecessor was a limited liability company that passed tax liability through to its members and accordingly did not record income tax expense.
Deferred Finance Charges
Costs associated with the revolving credit facility are deferred and amortized to interest expense over the term of the related financing. The amount of deferred financing costs incurred, and the amortization of deferred financing costs, was immaterial for all periods presented.
Derivative Financial Instruments
The Company enters into derivative contracts to manage its exposure to oil and gas price volatility. Commodity derivative contracts may take the form of swaps, puts, calls, or collars. Cash settlements from the Company’s commodity price risk management activities are recorded in the month the contracts mature. Any realized gains and losses on settled derivatives, as well as mark-to-market gains or losses, are aggregated and recorded to Commodity derivative (loss) gain, net on the statements of operations.
New Accounting Pronouncements
In June 2016, FASB issued ASU No. 2016-13, Financial Instruments—Credit Losses: Measurement of Credit Losses on Financial Instruments. The ASU includes changes to the accounting and measurement of financial assets requiring the Company to recognize an allowance for all expected credit related losses over the life of the financial asset at origination. This is different from the current practice, where an allowance is not recognized until the losses are considered probable. The new guidance was effective for the Company on January 1, 2023. Upon adoption, the ASU was applied using a modified retrospective transition method to the beginning of the earliest period in which the new guidance is effective. The adoption of the new guidance did not have a material impact on its financial statements and related disclosures.
17
Note 3—Asset Acquisitions
The Company acquires proved developed and proved undeveloped oil and gas properties that are proximate or complementary to existing properties and leases for strategic purposes.
During the three months ended June 30, 2023, the Company purchased proved oil and gas properties and proved leasehold for an aggregate purchase price of $3.1 million.
During the six months ended June 30, 2023, the Company purchased proved oil and gas properties and proved leasehold for an aggregate purchase price of $4.2 million. In addition, as part of the Spin-Off, $35.6 million of oil and gas properties and $5.0 million of net liabilities of Vitesse Oil were contributed in exchange for 2,120,312 shares of common stock of the Company for a total consideration of $30.6 million.
During the three and six months ended June 30, 2022, the Company purchased proved oil and gas properties and proved leaseholds for an aggregate purchase price of $5.9 million and $18.4 million, respectively.
Note 4—Fair Value Measurements
Accounting standards require certain assets and liabilities be reported at fair value in the consolidated financial statements and provide a framework for establishing that fair value. The framework for determining fair value is based on a hierarchy that prioritizes the inputs and valuation techniques used to measure fair value.
Fair values determined by Level 1 inputs use quoted prices in active markets for identical assets or liabilities that the Company has the ability to access.
Fair values determined by Level 2 inputs use other inputs that are observable, either directly or indirectly. These Level 2 inputs include quoted prices for similar assets and liabilities in active markets and other inputs, such as interest rates, yield curves, and forward commodity price curves, that are observable at commonly quoted intervals.
Level 3 inputs are unobservable inputs, including inputs that are available in situations where there is little, if any, market activity for the related asset or liability. These Level 3 fair value measurements are based primarily on management’s own estimates using pricing models, discounted cash flow methodologies, or similar techniques taking into account the characteristics of the asset or liability. Significant Level 3 inputs include estimated future cash flows used in determining the fair value of purchased oil and gas properties.
In instances where inputs used to measure fair value fall into different levels in the above fair value hierarchy, fair value measurements in their entirety are categorized based on the lowest level input that is significant to the valuation. The Company’s assessment of the significance of particular inputs to these fair value measurements requires judgment and considers factors specific to each asset or liability.
Recurring Fair Value Measurements
As of June 30, 2023, the Company’s derivative financial instruments are composed of commodity swaps. The fair value of the swap agreements is determined under the income valuation technique using a discounted cash flow model. The fair values of any options are determined under the income valuation technique using an option pricing model along with the stated amount of deferred premiums if applicable. The valuation models require a variety of inputs, including contractual terms, published forward commodity prices, volatilities for options, and discount rates, as appropriate. The Company’s estimates of fair value of derivatives include consideration of the counterparty’s creditworthiness, the Company’s creditworthiness, and the time value of money. The consideration of these factors results in an estimated exit price for each derivative asset or liability under a marketplace participant’s view. All of the significant inputs are observable, either directly or indirectly; therefore, the Company’s commodity derivative instruments are included within Level 2 of the fair value hierarchy (see Note 6).
Financial Instruments Not Measured at Fair Value
Note 5—Revolving Credit Facility
Revolving Credit Facility
In connection with the Spin-Off in January 2023, the Company entered into a secured revolving credit facility with Wells Fargo Bank, N.A., as administrative agent, and a syndicate of banks, as lenders (the “Revolving Credit Facility”). The Revolving Credit Facility amends and restates the revolving credit facility of the Predecessor (the “Prior Revolving Credit Facility”). The
18
Predecessor, as predecessor borrower under the Predecessor Revolving Credit Facility, assigned the liens and existing rights, liabilities and obligations under the Prior Revolving Credit Facility to the Company pursuant to the Revolving Credit Facility. The Revolving Credit Facility will mature on April 29, 2026. The Revolving Credit Facility permits borrowing on a revolving credit basis with availability equal to the least of (1) the aggregate elected commitments, (2) the borrowing base and (3) the maximum credit amount of $500.0 million. Our borrowing base under the Revolving Credit Facility is subject to regular, semi-annual redeterminations on or about April 1 and October 1 of each year based on, among other things, the value of our proved oil and natural gas reserves, as determined by the lenders in their discretion. As of June 30, 2023, the Company’s borrowing base was $245.0 million with an aggregate elected commitment of $170.0 million of which $41.0 million was outstanding.
At our option, borrowings under the Revolving Credit Facility bear interest at a rate unchanged from the Predecessor Revolving Credit Facility, which is either an adjusted forward-looking term rate based on SOFR (“Term SOFR”) or an adjusted base rate (“Base Rate”) (the highest of the administrative agent’s prime rate, the federal funds rate plus 0.50 % or the 30-day Term SOFR rate plus 1.0 %), plus an applicable margin expected to range from 1.75 % to 2.75 % with respect to Base Rate borrowings and 2.75 % to 3.75 % with respect to Term SOFR borrowings, in each case based on the current commitment utilization percentage. Interest is calculated and paid monthly in arrears. Additionally, the Company incurs an unused credit facility fee, paid quarterly, of 0.50 % of the unutilized commitment regardless of the borrowing base utilization percentage. As of June 30, 2023, the interest rate on the outstanding balance under the Revolving Credit Facility was 8.00 %.
Consistent with the Prior Revolving Credit Facility, the Revolving Credit Facility is guaranteed by all of our subsidiaries and is collateralized by a first priority lien on substantially all assets of Vitesse and its subsidiaries, including a first priority lien on properties representing a minimum of 85 % of the total present value of our proved oil and natural gas properties.
The Revolving Credit Facility contains various affirmative, negative and financial maintenance covenants. These covenants limit our ability to, among other things, incur or guarantee additional debt, make distributions to our equity holders, make certain investments and acquisitions, incur certain liens or permit them to exist, enter into certain types of transactions with affiliates, merge or consolidate with another company and transfer, sell or otherwise dispose of assets.
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)$500.0 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.
The Revolving Credit Facility contains covenants requiring us to maintain the following financial ratios tested on a quarterly basis: (1) a consolidated Total Funded Debt to consolidated EBITDAX ratio (in each case, as defined in the Revolving Credit Facility of not greater than 3.0 to 1.0; and (2) a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0. These financial covenants are consistent with the Predecessor Revolving Credit Facility. The Revolving Credit Facility also contains covenants that require that the Company enter into swap agreements covering not less than 40 % of reasonably anticipated PDP production for the following four quarters when the Utilization Percentage, as defined in the Revolving Credit Facility, is less than 50 % and covering at least 50 % of reasonably anticipated PDP production for the following eight quarters if the Utilization Percentage is 50 % or greater. The Revolving Credit Facility contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross default, bankruptcy and change in control. If an event of default exists under the Revolving Credit Facility the lenders will be able to terminate the lending commitments, accelerate the maturity of the Revolving Credit Facility and exercise other rights and remedies with respect to the collateral. The Company was in compliance with all financial covenants of the Revolving Credit Facility at June 30, 2023.
On May 2, 2023, the Company entered into an amendment to the Revolving Credit Facility in conjunction with the regular semi-annual borrowing base redetermination that reduced the borrowing base to $245 million (primarily related to lower commodity prices), reaffirmed elected commitments at $170 million and reduced hedging requirements in certain circumstances, among other items.
Prior Revolving Credit Facility
In May 2015, the Predecessor entered into a credit facility with a syndicate of banks as lenders led by Wells Fargo Bank, N.A. as the administrative agent with the Predecessor as the borrower, which originally matured in May 2020. The Prior Revolving Credit Facility was subsequently amended, and the maturity date was extended to April 2026. The most recent amendment was executed in April 2022 (the “April 2022 amendment”). The Prior Revolving Credit Facility specified an aggregate maximum credit amount equal to $500.0 million and a maximum borrowing base, as determined by the lenders. The determination of the borrowing base took into consideration the estimated value of the Predecessor’s oil and gas properties in accordance with the lenders’ customary
19
practices for oil and gas loans. The borrowing base was subject to scheduled redeterminations on a semiannual basis. The amount available for borrowing could be increased or decreased as a result of such redeterminations. As of December 31, 2022, the borrowing base under the Prior Revolving Credit Facility was $200.0 million with an elected commitment of $170.0 million of which $48.0 million was outstanding.
Prior to the April 2022 amendment, the Predecessor had the option to request borrowings under either a eurodollar loan or an alternative base rate loan. Eurodollar loans bore interest at the adjusted LIBOR plus an applicable margin ranging from 2.75 % to 3.75 % depending on the borrowing base utilization percentage. Alternative base rate loans bore interest at the higher of (a) the prime rate in effect on such day, (b) the federal funds effective rate in effect on such day plus 0.50 %, or (c) the adjusted LIBOR for a one-month interest period on such day plus an applicable margin ranging from 1.75 % to 2.75 % depending on the borrowing base utilization percentage. With the April 2022 amendment, at the Predecessor’s option, borrowings under the Prior Revolving Credit Facility bore interest at either an adjusted forward-looking term rate based on the Secured Overnight Financing Rate (“SOFR”) or an adjusted base rate (“Base Rate”) (the highest of the administrative agent’s prime rate, the Federal Funds rate plus 0.50 % or the 30-day SOFR rate plus 1.0 %), plus a spread ranging from 1.75 % to 2.75 % with respect to Base Rate borrowings and 2.75 % to 3.75 % with respect to SOFR borrowings, in each case based on the borrowing base utilization percentage. Interest was calculated and paid monthly in arrears. Additionally, the Predecessor incurred an unused credit facility fee of 0.50 % regardless of the borrowing base utilization percentage. As of December 31, 2022, the interest rate on the outstanding balance under the Prior Revolving Credit Facility was 7.42 %.
The Prior Revolving Credit Facility included customary terms and covenants that place limitations on certain types of activities, including the payment of dividends and distributions, and required satisfaction of certain financial covenants, such as minimum leverage and current ratios. The Prior Revolving Credit Facility also required excess cash at any point in time over $10.0 million to be repaid to the Borrowers (under certain defined conditions), subject to the terms in the Prior Revolving Credit Facility. The Company was in compliance with all financial covenants of the Prior Revolving Credit Facility at December 31, 2022. The Prior Revolving Credit Facility was guaranteed by the Company’s subsidiaries and was collateralized with a minimum of 85 % of the proved PV10 reserve value of the Company’s oil and gas properties.
In addition, the Prior Revolving Credit Facility placed additional conditions on the ability of the founding members of management to put their common units back to the Predecessor (see Note 10). These conditions included the establishment of maximum percentages of debt outstanding relative to the existing borrowing base and pro forma debt to earnings before interest, taxes, depletion, depreciation, amortization, and exploration expense (“EBITDAX”) ratios, as defined in the Prior Revolving Credit Facility, at the date of the permitted exercise.
Note 6—Derivative Instruments
The Company periodically enters into various commodity hedging instruments to mitigate a portion of the effect of oil and natural gas price fluctuations. The Company classifies commodity derivative assets and liabilities as current or noncurrent commodity derivative assets or current or noncurrent commodity derivative liabilities, whichever the case may be.
The following table summarizes the location and fair value amounts of all commodity derivative instruments in the balance sheet as of June 30, 2023, as well as the gross recognized derivative assets, liabilities, and amounts offset in the balance sheet:
| (in thousands) | GROSS RECOGNIZED FAIR VALUE ASSETS/ LIABILITIES | GROSS AMOUNTS OFFSET | NET RECOGNIZED FAIR VALUE ASSETS/ LIABILITIES | ||||||||||||||
| Commodity derivative assets: | |||||||||||||||||
| Current derivative assets | $ | $ | $ | ||||||||||||||
| Noncurrent derivative assets | |||||||||||||||||
| Total | $ | $ | $ | ||||||||||||||
| Commodity derivative liabilities: | |||||||||||||||||
| Current derivative liabilities | $ | $ | $ | ||||||||||||||
| Noncurrent derivative liabilities | |||||||||||||||||
| Total | $ | $ | $ | ||||||||||||||
The following table summarizes the location and fair value amounts of commodity derivative instruments in the balance sheet as of December 31, 2022, as well as the gross recognized derivative assets, liabilities, and amounts offset in the balance sheet:
20
| (in thousands) | GROSS RECOGNIZED FAIR VALUE ASSETS/ LIABILITIES | GROSS AMOUNTS OFFSET | NET RECOGNIZED FAIR VALUE ASSETS/ LIABILITIES | ||||||||||||||
| Commodity derivative assets: | |||||||||||||||||
| Current derivative assets | $ | $ | ( | $ | |||||||||||||
| Noncurrent derivative assets | ( | ||||||||||||||||
| Total | $ | $ | ( | $ | |||||||||||||
| Commodity derivative liabilities: | |||||||||||||||||
| Current derivative liabilities | $ | $ | ( | $ | |||||||||||||
| Noncurrent derivative liabilities | ( | ||||||||||||||||
| Total | $ | $ | ( | $ | |||||||||||||
As of June 30, 2023, the Company had the following crude oil swaps:
| CONTRACT | TYPE | TERM | VOLUME HEDGED (Bbls) | INDEX | ROUNDED FIXED PRICE | |||||||||||||||||||||||||||
| 1 | Swap | July 2023 - November 2023 | WTI-NYMEX | $ | ||||||||||||||||||||||||||||
| 2 | Swap | July 2023 - November 2023 | WTI-NYMEX | |||||||||||||||||||||||||||||
| 3 | Swap | July 2023 - November 2023 | WTI-NYMEX | |||||||||||||||||||||||||||||
| 4 | Swap | July 2023 - November 2023 | WTI-NYMEX | |||||||||||||||||||||||||||||
| 5 | Swap | July 2023 - November 2023 | WTI-NYMEX | |||||||||||||||||||||||||||||
| 6 | Swap | July 2023 - December 2023 | WTI-NYMEX | |||||||||||||||||||||||||||||
| 7 | Swap | July 2023 - March 2024 | WTI-NYMEX | |||||||||||||||||||||||||||||
| 8 | Swap | December 2023 - November 2024 | WTI-NYMEX | |||||||||||||||||||||||||||||
| 9 | Swap | December 2023 - November 2024 | WTI-NYMEX | |||||||||||||||||||||||||||||
| 10 | Swap | December 2023 - November 2024 | WTI-NYMEX | |||||||||||||||||||||||||||||
Due to the volatility of oil prices, the estimated fair values of the Company’s commodity derivative instruments are subject to large fluctuations from period to period.
The counterparties in the Company’s derivative instruments also participate in the Company’s Revolving Credit Facility; accordingly, the Company is not required to post collateral, as the counterparties have the right of offset for any derivative liabilities, and the Revolving Credit Facility is secured by the Company’s oil and gas assets. For further discussion related to the fair value of the Company’s derivatives, see Note 4.
Note 7—Accrued Liabilities
Accrued liabilities at June 30, 2023 and December 31, 2022 are summarized as follows:
| JUNE 30, | DECEMBER 31, | ||||||||||
| (in thousands) | 2023 | 2022 | |||||||||
| Accrued capital expenditures | $ | $ | |||||||||
| Accrued lease operating expenses, net | |||||||||||
| Accrued compensation | |||||||||||
| Other accrued liabilities | |||||||||||
| Accrued spin related expenditures | |||||||||||
| Total | $ | $ | |||||||||
Note 8—Related Party Transactions
21
promissory note was fully guaranteed by one of the members of 3B. Each of the two Initial Loans were collateralized by all of the common units held by 3B. In 2021, the $3.5 million promissory note was amended to remove the guarantee, change the interest rate to 10.0 percent and extend the maturity date to December 31, 2023. At the same time the $7.875 million promissory note was amended to extend the maturity date to December 31, 2023. The Initial Loans between 3B and VE Holding LLC were held outside of the Predecessor and were not a liability of the Predecessor. During 2022, there were $36.0 million of ratable distributions made to the common unit holders. The 3B distribution of $0.9 million was used to pay down a pro rata portion of the outstanding interest on the Initial Loans. The 3B common units and related loans were liquidated and terminated in connection with the Spin-Off.
In connection with the Company Agreement, in July 2018 certain executives entered into two separate promissory notes aggregating to $10.0 million with VE Holding LLC (the “2018 Notes”), which were collateralized by the MIUs granted to the respective executive. The 2018 Notes accrued interest at 3.0 percent per annum payable annually on December 31 and matured the earlier of July 1, 2024, an MIU exchange, or an acceleration event (as defined). The 2018 Notes could have been prepaid at any time but were subject to mandatory prepayment upon the issuance of any distributions from the Company related to the MIUs held by such executives. Additionally, the 2018 Notes were considered full recourse to each respective executive for a limited time, with such recourse reduced by one-third each December 31 through 2020. As the 2018 Notes were between VE Holding LLC and the executives, they did not represent liabilities of the Predecessor. The Founder MIUs and related promissory notes were liquidated and terminated in connection with the Spin-Off.
The Predecessor entered into an amended and restated services agreement (the “Services Agreement”) by and between the Predecessor, Vitesse Management, and Vitesse Oil on May 7, 2014. Per the Services Agreement, costs incurred by Vitesse Management was to be allocable between the Predecessor and Vitesse Oil initially at 50 50 percent or the quotient of the total contributed capital to the Predecessor made by its members and the sum of the total contributed capital to the Predecessor and Vitesse Oil by their respective members. As such, the Predecessor incurred 90 0.2 million and $0.7 million for the three and six months ended June 30, 2022, respectively. The amount due to the Predecessor from Vitesse Oil as of June 30, 2022 was immaterial. Vitesse Oil was acquired as part of the Spin-Off and accordingly 100% of Vitesse Management costs were incurred by the Company subsequent to the Spin-Off.
On July 1, 2016, the Predecessor entered into a separate services agreement between Vitesse Management and JETX Energy, LLC (“JETX”), formerly known as Juneau Energy, LLC, another entity owned by JFG with common management. Per this services agreement, Vitesse Management is to provide JETX certain administrative services and supervise, administer, and manage the business affairs and operations of JETX and its subsidiaries for a service provider fee of $0.2 million per month. The term of this service agreement extends for an unlimited amount of time; however, it is subject to termination by either Vitesse Management or JETX if provided written consent following the first anniversary or a final exit event. During the three and six months ended June 30, 2023, the Company recorded its net share of fees from JETX of $0.7 million and $1.3 million, respectively. During the three and six months ended June 30, 2022, the Company recorded its net share of fees from JETX of $0.6 million and $1.2 million, respectively. These fees are classified as a reduction to general and administrative expenses on the accompanying statements of operations.
On July 1, 2016, the Predecessor implemented the Employee Participation Plan (“EPP”) pursuant to which employees, consultants, or independent contractors of the Predecessor may be invited to personally acquire a working interest in new oil and gas wells in which the Predecessor elects to participate. The EPP was subsequently amended on January 1, 2018. The tranches were not to exceed a maximum of $2.0 million of capital expenditures in the aggregate for each year. Participants in the EPP were required to fund their proportion of development costs and ongoing operating expenses of those specific wellbores. Compensation expense is measured by the allocable amount of the value of the assigned wellbore leasehold costs which has historically been immaterial. On November 30, 2022, the Predecessor repurchased the outstanding EPP working interest for $4.9 million in accordance with the terms of the plan and terminated the EPP.
Note 9—Commitments and Contingencies
Litigation
From time to time, the Company may be involved in litigation relating to claims arising out of its operations in the normal course of business. As of the date of this report, management of the Company was unaware of any material legal proceedings against the Company. The Company maintains insurance to cover certain actions.
Note 10—Equity
Authorized Capital Stock
The Amended and Restated Certificate of Incorporation authorized capital stock consisting of 95,000,000 shares of common stock, par value $0.01 per share and 5,000,000 shares of preferred stock, par value $0.01 per share.
22
Common Stock
During the six months ended June 30, 2023 the following transactions related to our common stock occurred:
■3B transferred all of its Predecessor equity interests to JFG as repayment for the Initial Loans;
■JFG distributed the remaining Predecessor equity interests to its shareholders in the Spin-Off, which amounted to 25,628,162 shares of common stock in the Company;
■the Transitional Equity Award Adjustment Plan (the “Transitional Plan”), as discussed further below, was implemented and resulted in the following issuances to current and former directors and employees of JFG:
◦286,729 restricted stock awards (included in issuance of common stock in exchange for Vitesse Energy, LLC on the Condensed Consolidated Statements of Equity), of which 50,744 were issued as common shares during the period;
◦1,475,631 restricted stock units, of which 603,249 were issued as common shares during the period;
■Predecessor MIUs granted to Predecessor employees other than the Predecessor’s two founders were exchanged for 163,544 shares of common stock;
■Vitesse Oil was contributed in exchange for 2,120,312 common shares;
■3,153,122 restricted stock units were issued to officers, directors and employees;
■14,600 shares of common stock were repurchased and retired as part of our Stock Repurchase Program, as discussed further below.
■Declared dividends of $32.8 million on common stock during the period.
Preferred Stock
Our Amended and Restated Certificate of Incorporation authorizes our board of directors to designate and issue from time to time one or more series of preferred stock without stockholder approval. Our board of directors may fix and determine the designation, relative rights, preferences and limitations of the shares of each such series of preferred stock. There are no present plans to issue any shares of preferred stock and there are currently no shares outstanding.
Long-Term Incentive Plan
The Company’s long-term incentive plan (“LTIP”) provides for the granting of various forms of equity-based awards, including stock options awards, stock appreciation rights awards, restricted stock awards, restricted stock unit awards, performance awards, cash awards and other stock-based awards to employees, directors and consultants of the Company. Under the LTIP, 3,960,000 shares were initially available to be awarded and as of June 30, 2023, there were 806,878 shares available to be granted.
The following is a summary of LTIP activity during the six months ended June 30, 2023:
| Shares of restricted stock unit awards | Weighted-Average Price on Date of Grant | ||||||||||
| Outstanding at January 1, 2023 | $ | ||||||||||
| Granted | |||||||||||
| Vested | |||||||||||
| Forfeited | |||||||||||
| Outstanding at March 31, 2023 | $ | ||||||||||
| Granted | |||||||||||
| Vested | |||||||||||
| Forfeited | |||||||||||
| Outstanding at June 30, 2023 | $ | ||||||||||
For restricted stock units, the Company recognizes the grant date fair-value of awards over the requisite service period as stock-based compensation expense on a straight-line basis except when provisions are present that accelerate vesting.
During the three months ended June 30, 2023, the Company recognized $1.4 million of equity-based compensation expense relating to these restricted stock units.
During the six months ended June 30, 2023, the Company recognized $29.4 million of equity-based compensation expense relating to these restricted stock units of which $26.8 million, or 1,863,000 restricted stock units, was for awards that had a retirement provision and were granted to retirement-eligible employees and therefore resulted in immediate recognition of expense.
23
As of June 30, 2023, there is $16.2 million of unrecognized equity-based compensation expense related to unvested restricted stock unit awards. The cost is expected to be recognized through January 2027, over a weighted-average period of 3.04 years.
Transitional Equity Award Adjustment Plan
JFG’s outstanding compensatory equity awards were adjusted into equity incentive awards denominated in part in shares of Vitesse common stock in connection with the Spin-Off. All adjusted awards are subject to generally the same vesting, exercisability, expiration, settlement and other material terms and conditions as applied to the applicable original JFG award immediately before the Spin-Off, except that equity awards relating to our common stock were subject to accelerated vesting, exercisability and in some cases settlement in the event of a change in control of the Company. All of the Transitional Plan equity awards discussed below were granted by JFG and therefore do not result in any compensation cost to the Company.
Transitional Plan Options
Each JFG stock option that did not remain an option to purchase shares of only JFG common stock was converted into both a post-Spin-Off option to purchase shares of JFG common stock and an option to purchase shares of Vitesse common stock. The exercise price of such JFG stock option and the exercise price and number of shares subject to such Vitesse stock option was adjusted so that (i) the aggregate intrinsic value of such post-Spin-Off JFG stock option and Vitesse stock option immediately after the Spin-Off equals the aggregate intrinsic value of the JFG stock option as measured immediately before the Spin-Off and (ii) the aggregate exercise price of such post-Spin-Off JFG stock option and Vitesse stock option equals the aggregate exercise price of the JFG stock option immediately before the Spin-Off, subject to rounding. Upon completion of the Spin-Off, 457,866 options were granted and no 6.1 million at June 30, 2023 and the maximum number of shares of common stock that could be issued under the plan is 457,866 .
Transitional Plan Restricted Units
Each JFG restricted stock unit award and performance stock unit award (other than those that will remain awards denominated in shares of only JFG stock, which includes the portion of any performance stock unit award that may be earned above the designated target level), including any additional stock units accrued as a result of dividend equivalents, was adjusted by the grant of a Vitesse restricted stock unit award. Upon completion of the Spin-Off, 1,475,631 restricted stock units were granted in respect of these JFG awards. These restricted stock unit awards have no remaining performance or service conditions to satisfy, or any other vesting condition, and generally accrue dividends declared on common stock but have deferred issuance dates through January 2, 2099. During the three and six months ended June 30, 2023, zero and 603,249 restricted stock units, respectively, were released as common stock or cashed out as fractional units.
Transitional Plan Restricted Stock Awards
Holders of a JFG restricted stock award received 286,729 shares of our common stock upon completion of the Spin-Off, which shares are subject to the provisions of the Transitional Plan, including generally the same risk of forfeiture and other conditions as applied to the original JFG restricted stock award. These restricted stock awards have no remaining performance or service conditions to satisfy, or any other vesting condition, and are paid dividends on common stock as declared but have deferred issuance dates through September 28, 2029. During the three and six months ended June 30, 2023, 11,454 and 50,744 restricted stock awards. respectively, were released as common stock.
The remaining restricted stock units and restricted stock awards are scheduled to be released as common stock as follows:
| Year | Restricted stock units | Restricted stock awards | Total | |||||||||||||||||
| 2023 | ||||||||||||||||||||
| 2024 | ||||||||||||||||||||
| 2025 | ||||||||||||||||||||
| 2026 | ||||||||||||||||||||
| 2027 | ||||||||||||||||||||
| Thereafter | ||||||||||||||||||||
| Total | ||||||||||||||||||||
The Transitional Plan governs the terms and conditions of the new Vitesse awards issued as an adjustment to JFG awards at the effective time of the Spin-Off, but will not be used to make any grants following the Spin-Off.
24
Stock Repurchase Program
In February, 2023, the Board approved a stock repurchase program authorizing the repurchase of up to $60 million of the Company’s common stock.
Under the Stock Repurchase Program, we may repurchase shares of our common stock from time to time in open market transactions or such other means as will comply with applicable rules, regulations and contractual limitations. The Board of Directors may limit or terminate the Stock Repurchase Program at any time without prior notice. The extent to which the Company repurchases its shares of common stock, and the timing of such repurchases, will depend upon market conditions and other considerations as may be considered in the Company’s sole discretion.
During the six months ended June 30, 2023, the Company repurchased 14,600 shares for $0.2 million and the shares were subsequently retired.
Net Income (Loss) Per Common Share
The Company uses the two-class method of calculating earnings per share because certain of the Company’s unvested LTIP RSUs qualify as participating securities.
Basic earnings per share amounts have been computed as (i) net income (loss) (ii) less distributed and undistributed earnings allocated to participating securities (iii) divided by the weighted average number of basic shares outstanding for the periods presented. Diluted earnings per share amounts have been computed as (i) basic net income attributable to common stockholders (ii) plus the adjustment of distributed and undistributed earnings allocated to participating securities (iii) divided by the weighted average number of diluted shares outstanding for the periods presented.
The components of basic and diluted net income (loss) per share attributable to common stockholders are as follows:
| FOR THE THREE MONTHS ENDED | FOR THE SIX MONTHS ENDED | ||||||||||
| (in thousands except share and per share amounts) | JUNE 30, 2023 | JUNE 30, 2023 | |||||||||
| Numerator for earnings per common share: | |||||||||||
| Net income (loss) attributable to Vitesse Energy, Inc. | $ | $ | ( | ||||||||
Allocation of earnings to participating securities(1) | ( | ||||||||||
| Net income (loss) attributable to common shareholders | $ | $ | ( | ||||||||
| Adjustment to allocation of earnings to participating securities related to diluted shares | |||||||||||
| Net income (loss) attributable to common shareholders for diluted EPS | $ | $ | ( | ||||||||
| Denominator for earnings per common share: | |||||||||||
| Weighted average common shares outstanding - basic | |||||||||||
| Weighted average Transitional Share RSUs outstanding with no future service required | |||||||||||
| Denominator for basic earnings per common share | |||||||||||
| LTIP RSUs | |||||||||||
| Transitional Share options | |||||||||||
| Denominator for diluted earnings per common share | |||||||||||
| Net income (loss) per common share: | |||||||||||
| Basic | $ | $ | ( | ||||||||
| Diluted | $ | $ | ( | ||||||||
| Shares excluded from diluted earnings per share due to anti-dilutive effect: | |||||||||||
| LTIP RSUs | |||||||||||
| Transitional Share options | |||||||||||
(1)Certain unvested LTIP RSUs represent participating securities because they participate in nonforfeitable dividends with the common equity holders of the Company. Participating earnings represent the distributed and undistributed earnings of the Company attributable to the participating securities. These unvested LTIP RSUs do not participate in undistributed net losses as they are not contractually obligated to do so.
25
Predecessor Members’ Equity
The Predecessor had two classes of membership units, with the following units authorized, issued, and outstanding as of December 31, 2022:
| AUTHORIZED | ISSUED AND OUTSTANDING | ||||||||||
| Common units | |||||||||||
| Management incentive units | |||||||||||
Common Units
Common units of the Predecessor were issued at $1 per unit, with an aggregate capital commitment from all common members of $450 million. There initially were five managers on the board of managers, with three managers designated by JFG and two managers designated by 3B. For voting purposes, each manager was entitled to one vote, and the affirmative vote of a majority of the board of managers, including at least one JFG manager, was required to ratify any significant decisions.
Management Incentive Units
Predecessor management incentive units were issued by the Predecessor to eligible employees and/or consultants. All MIUs were nonvoting and provided the MIU holders the opportunity to participate in distributions after the common unit holders received a specified return.
MIUs were granted to the two founding members of management (“Founder MIUs”) and certain other employees of the Predecessor (“Non-Founder MIUs”). MIUs were subject to vesting requirements and forfeiture provisions specific to the Founder MIUs and Non-Founder MIUs, as outlined in the Company Agreement, employment agreement, grant letters, and other supporting MIU documentation.
The Predecessor accounted for Non-Founder MIUs as liability-based awards until the respective holder had borne the risk of unit ownership, at which point the value of the liability was reclassified outside of permanent equity. While the awards were classified as liabilities, compensation expense was recorded through the vesting period, and changes in the estimated fair market value of the liability, were recorded in earnings. Once reclassified outside of permanent equity increases in the estimated fair market value of the award were recorded through members’ equity. During the three and six months ended June 30, 2022, the Predecessor recorded a decrease of $4.8 million and $7.0 million, respectively, through members’ equity to adjust the Non-Founder MIUs to fair market value.
A summary of the Predecessor’s activity related to Non-Founder MIUs for the three and six months ended June 30, 2022 is presented below:
| FOR THE THREE MONTHS ENDED | FOR THE SIX MONTHS ENDED | ||||||||||
| JUNE 30, 2022 | JUNE 30, 2022 | ||||||||||
| Nonvested at period end | |||||||||||
| Granted during the period | |||||||||||
| Vested during the period | |||||||||||
| Forfeited during the period | |||||||||||
| Fair value of MIUs vested during the period | $ | million | $ | million | |||||||
As of December 31, 2022, there was no unrecognized compensation cost related to nonvested unit-based compensation arrangements.
As a result of each of the management founders’ receipt of an in-substance nonrecourse note (the “2018 Notes”) that were each collateralized by all of the Founder MIUs held by the respective executive, for accounting purposes, the Predecessor granted each of the management founders an in-substance call option that is within the scope of accounting guidance related to share-based compensation (the “Founder MIU Option Grant”). Due to the nature and terms of the Founder MIU Put Option, the Founder MIU Option Grant was classified as a liability award, remeasured at fair market value at each reporting date with the change in fair market value recorded to earnings.
26
| FOR THE THREE MONTHS ENDED | FOR THE SIX MONTHS ENDED | ||||||||||
| (in thousands) | JUNE 30, 2022 | JUNE 30, 2022 | |||||||||
| Common Unit Option Grant | $ | $ | |||||||||
| Founder MIU Option Grant | |||||||||||
| Non-Founder MIUs | |||||||||||
| Total | $ | $ | |||||||||
As of December 31, 2022, the intrinsic value of the Founder MIU Option Grant and the Common Unit Option Grant, was determined to be de minimis given the limited amount of time until the instruments were settled and prevailing economic factors. The Option Grants were forfeited on January 13, 2023 with the executives agreeing to settle their common units and Founder MIUs in exchange of JFG forgiving the 2018 Notes and any accrued interest. The December 31, 2022 liability and the factors considered in valuing the liability at December 31, 2022 are not presented due to the immaterial nature of these items.
Measurement of Unit-Based Compensation
The Predecessor recorded the Non-founder MIUs, Founder MIU Option Grant, and Common Unit Option Grant at fair value at the date of grant and at each balance sheet date, which results in compensation cost being measured at fair value. As noted above, vested Non-founder MIUs, where the respective holder has borne the risk of ownership, are recorded within temporary equity, with changes in fair value recorded within members’ equity.
The fair value of each of the Founder MIU Option Grant and the Common Unit Option Grant (collectively “the Options”) were estimated using a Black Scholes Model. As the Predecessor did not have publicly-traded equity, it incorporated data from a group of publicly-traded peer companies when estimating fair value. Expected volatilities were based on the historical volatility of our identified peer group of companies. The expected term of the Options was determined based on the timing of an exit or liquidity event. The risk-free rate for periods within the expected life of the option was interpolated from the US constant maturity treasury rate, for a term corresponding to the expected term.
Distributions
Distributions of funds associated with common units follow a prescribed framework, which is outlined in detail in the Company Agreement. In general, distributions were first allocated to those unitholders based on their allocable share, as defined in the Company Agreement. Each unitholder would then receive a distribution in accordance with the tiered waterfall, as defined in the Company Agreement. The Company declared $18 million and $36 million, respectively, of distributions on common units during the three and six months ended June 30, 2022.
Earnings Per Unit
The Predecessor had two classes of equity in the form of common units and MIUs that were vested and where the holder has borne the risks and rewards of ownership at which point the MIU was reclassified from liabilities to outside of permanent equity. Both common units and temporary equity classified MIUs are considered common units, and distributions were made in accordance with the Company Agreement. As such, we present earnings per unit (“EPU”) for both classes of equity. In calculating EPU, we apply the two-class method. Under the two-class method net income (loss) attributable to common units is allocated to common units and other participating securities in proportion to the claim on earnings of each participating security after giving effect to distributions declared during the period, if any. The following table sets forth the computation of basic and diluted net income (loss) per unit:
27
| FOR THE THREE MONTHS ENDED | FOR THE SIX MONTHS ENDED | ||||||||||
| (In thousands except unit and per unit amounts) | JUNE 30, 2022 | JUNE 30, 2022 | |||||||||
| Common Units | |||||||||||
| Net income | $ | $ | |||||||||
| less: income allocable to participating securities | |||||||||||
| In-substance options on common units (Common Unit Option Grant) | ( | ( | |||||||||
| In-substance options on Founder MIUs (Founder MIU Option Grant) | |||||||||||
| Non-Founder MIUs classified as temporary equity | |||||||||||
| Non-Founder MIUs classified as liabilities | |||||||||||
| Net income (loss) attributable to common unitholders | |||||||||||
| Weighted Average Common Units Outstanding | |||||||||||
| less: Common Units accounted for as in-substance options | ( | ( | |||||||||
| Weighted Average Common Units Outstanding | |||||||||||
| Basic and Diluted EPU | $ | $ | |||||||||
| Temporary Equity Classified MIUs | |||||||||||
| Income allocable to Non-Founder MIUs classified as temporary equity | $ | $ | |||||||||
| MIUs classified in temporary equity | |||||||||||
| Basic and Diluted EPU | $ | $ | |||||||||
Note 11—Income Taxes
For the three and six months ended June 30, 2023 the Company recorded income tax expense of $6.8 million and $47.2 million, respectively. The Company did no
Our provision for income taxes for the three and six months ended June 30, 2023 differs from the amount that would be provided by applying the U.S. federal statutory rate of 21% to pre-tax book loss primarily due to (i) deferred tax expense reflected as a discrete item related to the change in tax status of Vitesse Energy from a partnership to a corporation as part of the Spin-Off, (ii) §162(m) limitations on certain covered employee compensation, and (iii) state income taxes. Vitesse Energy's change in tax status resulted in the recording of a $44.1 2.4 million deferred tax liability in connection with its acquisition of Vitesse Oil as part of the Spin-Off.
Note 12—Subsequent Events
On July 27, 2023, Vitesse’s Board of Directors declared a regular quarterly cash dividend for Vitesse’s common stock of $0.50 per share for stockholders of record as of September 15, 2023, which will be paid on September 29, 2023.
Other than the above disclosure or other subsequent events disclosed elsewhere in the notes to the financial statements, there were no material subsequent events.
28
Item 2. 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 Condensed Consolidated Financial Statements and the notes thereto included under Part I – Financial Information. 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 our Annual Report on Form 10-K for the fiscal year ended December 31, 2022 in the section entitled Part I. Item 1A Risk Factors and in this Quarterly Report on Form 10-Q in the sections entitled Part II, Item 1A Risk Factors and “Cautionary Statement Concerning Forward-Looking Statements.”
As further described in Note 1 – Nature of Business in Part I, Item 1 of this Quarterly Report, we completed the Spin-Off on January 13, 2023. The financial information presented herein is (i) for periods prior to January 13, 2023, that of our Predecessor, and (ii) for periods after January 13, 2023, that of Vitesse Energy, Inc. and its subsidiaries.
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 and growing 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 Bakken and Three Forks formations of 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 June 30, 2023, we had a working interest in 5,507 gross (148.6 net) productive wells and 278 gross (8.5 net) wells that were being drilled or completed, and an additional 432 gross (11.0 net) wells that had been permitted for development by our operators. During the three and six months ended June 30, 2023, our average production was 11,359 Boe per day and 11,441 Boe per day, respectively with 67% of production from oil.
Our financial and operating performance for the three months ended June 30, 2023 included the following:
■Net income of $9.6 million.
■Total revenue of $51.6 million.
■Cash flows from operations of $39.0 million.
■Declared quarterly dividend of $0.50 per share to our common stockholders.
■Reduced outstanding indebtedness from $48.0 million at December 31, 2022 to $41.0 million at June 30, 2023.
■Increased our production by 16% over the same period in 2022.
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. Our operators in the Williston Basin 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 crude oil production limits from OPEC. On June 4, 2023, OPEC plus Russia and certain of its allies agreed to reduce their overall production targets by an additional 1.4 million Bbl per day beginning in January 2024. This cut is in addition to the reductions in production of approximately 1.66 million Bbl per day, announced on April 2, 2023, and 2 million Bbl per day, announced in October 2022. Further, Saudi Arabia announced a separate voluntary production cut for July 2023 of 1 million Bbl per day which, in July 2023, was subsequently extended into August 2023. Also in July 2023, Russia announced a separate voluntary production cut of 500,000 Bbl per day for August 2023. The ongoing conflict between Russia and Ukraine 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 2023, our earnings and operating cash flows can vary substantially, and are subject to external factors over which we have no control. 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
29
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 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 well head price for oil and the WTI benchmark price is primarily driven by the cost to transport oil via train, pipeline or truck to refineries. The price differential between our well head price for natural gas and the WTI 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 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.
Depreciation, depletion, amortization and accretion. Depreciation, depletion, amortization and accretion 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 the three and six months ended June 30, 2023 and 2022, general and administrative expenses included one-time 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. 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.
30
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.
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 we use to reduce our exposure to fluctuations in the price of oil;
■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.
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 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 WTI benchmark price during the three months ended June 30, 2023 was negative $3.78 per barrel, as compared to negative $3.22 per barrel during the three months ended June 30, 2022, primarily due to less favorable local market pricing as compared to the benchmark price. Our net realized gas price during the three months ended June 30, 2023 was $1.41 per Mcf, representing a 65% realization relative to average Henry Hub pricing, compared to a net realized gas price of $8.35 per Mcf during the three months ended June 30, 2022, representing a 111% realization relative to average Henry Hub pricing. Fluctuations in our 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.
Market Conditions
The price received for the oil and natural gas our operators 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 war between Russia and Ukraine and the strength of the U.S. dollar can impact oil prices.
Historically, commodity prices have been volatile and we expect the volatility to continue in the future. Factors impacting the future oil supply balance are world-wide demand for oil, as well as world-wide oil production.
Prices for various quantities of oil, natural gas and NGLs that our operators produce significantly impact our revenues and cash flows. The following table lists average NYMEX prices for oil and natural gas for the periods presented.
31
| THREE MONTHS ENDED JUNE 30, | |||||||||||
Average NYMEX Prices (1) | 2023 | 2022 | |||||||||
| Oil (per Bbl) | $ | 73.56 | $ | 108.52 | |||||||
| Natural Gas (per MMBtu) | 2.33 | 7.50 | |||||||||
| SIX MONTHS ENDED JUNE 30, | |||||||||||
Average NYMEX Prices (1) | 2023 | 2022 | |||||||||
| Oil (per Bbl) | $ | 74.77 | $ | 101.77 | |||||||
| Natural Gas (per MMBtu) | 2.54 | 6.04 | |||||||||
(1)Based on average daily NYMEX closing prices.
The average second quarter 2023 WTI oil price was $73.56 per barrel or 32% lower than the average WTI price per barrel in the second quarter of 2022. Our settled derivatives increased our realized oil price per barrel by $2.28 in the second quarter of 2023 and decreased our realized oil price per barrel by $28.26 in the second quarter of 2022. Our average second quarter 2023 realized oil price per barrel after reflecting settled derivatives was $72.18 compared to $77.40 during the same period in 2022. The average second quarter 2023 NYMEX natural gas price was $2.33 per MMBtu, or 69% lower than the average NYMEX price per MMBtu in the second quarter of 2022. In the second quarter of 2023 and 2022, we had no natural gas derivatives in place and our realized price was $1.41 per Mcf as compared $8.35 per Mcf during the second quarter of 2022.
The average year-to-date 2023 WTI oil price was $74.77 per barrel or 27% lower than the 2022 average year-to-date WTI price per barrel. Our settled derivatives increased our 2023 year-to-date realized oil price per barrel by $1.68 and decreased our realized oil price per barrel by $24.67 during the same period in 2022. Our average 2023 year-to-date realized oil price per barrel after reflecting settled derivatives was $73.10 compared to $73.05 during the same period in 2022. The average 2023 year-to-date realized NYMEX natural gas price was $2.54 per MMBtu, or 58% lower than the average NYMEX price per MMBtu during the same period in 2022. Year-to-date 2023, we had no natural gas derivatives in place and our realized price was $2.53 per Mcf as compared to the same period in 2022 when our realized price was $7.89 per Mcf and $7.72 per Mcf before and after settled derivatives, respectively.
We employ a hedging program that mitigates the risk associated with fluctuations in commodity prices. For detailed information on our commodity hedging program, see Part I. Item 3 Quantitative and Qualitative Disclosures about Market Risk and Note 6 (“Derivative Instruments”) to the Condensed Consolidated Financial Statements.
32
Results of Operations
Three Months Ended June 30, 2023 Compared with Three Months Ended June 30, 2022
The following table sets forth selected financial and operating data for the periods indicated.
| QUARTER ENDED JUNE 30, | INCREASE (DECREASE) | ||||||||||||||||||||||
| ($ in thousands, except production and per unit data) | 2023 | 2022 | AMOUNT | PERCENT | |||||||||||||||||||
| Financial and Operating Results: | |||||||||||||||||||||||
| Revenue | |||||||||||||||||||||||
| Oil | $ | 48,733 | $ | 64,640 | $ | (15,907) | (25 | %) | |||||||||||||||
| Natural gas | 2,855 | 14,157 | (11,302) | (80 | %) | ||||||||||||||||||
| Total revenue | $ | 51,588 | $ | 78,797 | $ | (27,209) | (35 | %) | |||||||||||||||
| Operating Expenses | |||||||||||||||||||||||
| Lease operating expense | $ | 9,316 | $ | 7,661 | $ | 1,655 | 22 | % | |||||||||||||||
| Production taxes | 4,919 | 6,866 | (1,947) | (28 | %) | ||||||||||||||||||
| General and administrative | 4,461 | 3,633 | 828 | 23 | % | ||||||||||||||||||
| Depletion, depreciation, amortization, and accretion | 18,748 | 14,994 | 3,754 | 25 | % | ||||||||||||||||||
| Equity-based compensation | 1,428 | 16,292 | (14,864) | (91 | %) | ||||||||||||||||||
| Interest Expense | $ | 1,115 | $ | 1,044 | $ | 71 | 7 | % | |||||||||||||||
| Commodity Derivative Gain (Loss), Net | $ | 4,779 | $ | (11,558) | $ | 16,337 | 141 | % | |||||||||||||||
Income Tax Expense | $ | 6,812 | $ | — | $ | 6,812 | 100 | % | |||||||||||||||
| Production Data: | |||||||||||||||||||||||
| Oil (MBbls) | 697 | 612 | 85 | 14 | % | ||||||||||||||||||
| Natural gas (MMcf) | 2,018 | 1,696 | 322 | 19 | % | ||||||||||||||||||
| Combined volumes (MBoe) | 1,034 | 894 | 140 | 16 | % | ||||||||||||||||||
| Daily combined volumes (Boe/d) | 11,359 | 9,828 | 1,531 | 16 | % | ||||||||||||||||||
| Average Realized Prices before Hedging: | |||||||||||||||||||||||
| Oil (per Bbl) | $ | 69.90 | $ | 105.66 | $ | (35.76) | (34 | %) | |||||||||||||||
| Natural gas (per Mcf) | 1.41 | 8.35 | (6.94) | (83 | %) | ||||||||||||||||||
| Combined (per Boe) | 49.91 | 88.10 | (38.19) | (43 | %) | ||||||||||||||||||
| Average Realized Prices with Hedging: | |||||||||||||||||||||||
| Oil (per Bbl) | $ | 72.18 | $ | 77.40 | $ | (5.22) | (7 | %) | |||||||||||||||
| Natural gas (per Mcf) | 1.41 | 8.35 | (6.94) | (83 | %) | ||||||||||||||||||
| Combined (per Boe) | 51.45 | 68.78 | (17.33) | (25 | %) | ||||||||||||||||||
| Average Costs (per Boe): | |||||||||||||||||||||||
| Lease operating | $ | 9.01 | $ | 8.57 | $ | 0.44 | 5 | % | |||||||||||||||
| Production taxes | 4.76 | 7.68 | (2.92) | (38 | %) | ||||||||||||||||||
| General and administrative | 4.32 | 4.06 | 0.26 | 6 | % | ||||||||||||||||||
| Depletion, depreciation, amortization, and accretion | 18.14 | 16.76 | 1.38 | 8 | % | ||||||||||||||||||
Oil and Natural Gas Revenue and Volumes. Oil and natural gas revenue decreased to $51.6 million for the three months ended June 30, 2023 from $78.8 million for the three months ended June 30, 2022. The decrease in oil and natural gas revenue was due to a 43% decrease in the average realized prices per Boe before hedging, which was partially offset by a 16% increase in production volumes for the three months ended June 30, 2023. The decrease in average realized prices per Boe before hedging decreased oil and natural gas revenue by approximately $34.2 million, while the increase in production volumes increased oil and natural gas revenue by approximately $7.0 million.
Our oil price differential to the weighted average WTI benchmark price during the three months ended June 30, 2023 was negative $3.78 per barrel, as compared to negative $3.22 per barrel during the three months ended June 30, 2022, primarily due to less favorable local market pricing as compared to the benchmark price. Our net realized gas price during the three months ended June 30, 2023 was $1.41 per Mcf, representing a 65% realization relative to weighted average Henry Hub pricing, compared to a
33
net realized gas price of $8.35 per Mcf during the three months ended June 30, 2022, representing a 111% realization relative to weighted average Henry Hub pricing. 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, 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.
The decreases in realized oil and gas prices was primarily due to lower benchmark commodity prices in the three months ended June 30, 2023 as compared to the three months ended June 30, 2022.
Lease Operating Expense. Lease operating expense increased to $9.01 per Boe for the three months ended June 30, 2023 from $8.57 per Boe for the three months ended June 30, 2022. The increase per Boe for the three months ended June 30, 2023 compared with the three months ended June 30, 2022 was related to higher workover and service costs. The increased workover costs were responsible for approximately $0.36/Boe of the increase and should result in increased production when these wells return to production.
Production Tax Expense. Total production taxes decreased to $4.9 million for the three months ended June 30, 2023 from $6.9 million for the three months ended June 30, 2022. 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 9.5% and 8.7% for the three months ended June 30, 2023 and 2022, respectively. The increase in the production tax rate for the three months ended June 30, 2023 was 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 $4.5 million for the three months ended June 30, 2023 from $3.6 million for the three months ended June 30, 2022. General and administrative expense on a per Boe basis increased to $4.32 for the three months ended June 30, 2023 from $4.06 for the three months ended June 30, 2022.The increase in general and administrative expense per Boe was primarily due to higher costs associated with being a public company.
DD&A. DD&A increased to $18.7 million for the three months ended June 30, 2023 compared with $15.0 million for the three months ended June 30, 2022. The increase of $3.8 million, or 25% was the result of a 16% increase in production and a $1.38/Boe increase in the DD&A rate for the three months ended June 30, 2023 compared with the three months ended June 30, 2022. The higher DD&A rate was driven by lower reserves due to lower oil and gas prices in 2023. The increase in production accounted for a $2.6 million increase in DD&A expense while the increase in the DD&A rate accounted for a $1.2 million increase in DD&A expense.
For the three months ended June 30, 2023, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate (excluding depreciation, amortization and accretion) of $17.98 per Boe compared with $16.65 per Boe for the three months ended June 30, 2022.
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 June 30, 2023, the Company granted 3,153,122 restricted stock units to employees and directors at a weighted-average grant date fair value of $14.47 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. Equity-based compensation expense was $1.4 million for the three months ended June 30, 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 expense was $16.3 million for the three months ended June 30, 2022 .
Interest Expense. Interest expense increased to $1.1 million for the three months ended June 30, 2023 from $1.0 million for the three months ended June 30, 2022. The increase for the three months ended June 30, 2023 was due to a higher SOFR interest rate in the three months ended June 30, 2023 despite the balance of debt outstanding declining to $41.0 million at June 30, 2023 from $84.0 million at June 30, 2022. The higher interest rate was due to increases to the federal funds rate by the Federal Reserve throughout 2022 and into the second quarter of 2023.
Commodity Derivative Gain (Loss), Net. The commodity derivative gain was $4.8 million for the three months ended June 30, 2023 compared with a loss of $11.6 million for the three months ended June 30, 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.
34
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.
| QUARTER ENDED JUNE 30, | |||||||||||
| (in thousands) | 2023 | 2022 | |||||||||
Realized gain (loss) on commodity derivatives (1) | $ | 1,595 | $ | (17,287) | |||||||
Unrealized gain on commodity derivatives (1) | 3,184 | 5,729 | |||||||||
Total commodity derivative gain (loss) | $ | 4,779 | $ | (11,558) | |||||||
(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 statements of operations included in this Form 10-Q. 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 the three months ended June 30, 2023, approximately 50% of our oil volumes and none of our natural gas volumes were subject to financial hedges, which resulted in a realized gain on oil derivatives of $1.6 million. In the three months ended June 30, 2022, approximately 61% of our oil volumes and none of our natural gas volumes were covered by financial hedges, which resulted in a realized loss on oil derivatives of $17.3 million.
At June 30, 2023, all of our derivative contracts are recorded at their fair value, which was a net asset of $9.7 million, an increase of $9.9 million from the $0.2 million net liability recorded as of December 31, 2022. The increase was primarily due to changes to forward commodity prices relative to prices on our open commodity derivative contracts.
Income Tax Expense. In January 2023, the Predecessor was contributed into Vitesse resulting in a change in tax status. For the three months ended June 30, 2023, we recorded income tax expense of $6.8 million related to federal and state income taxes. The provision for income taxes for the three months ended June 30, 2023 differs from the amount that would be provided by applying the statutory U.S. federal income tax rate of 21% to pre-tax income primarily due to §162(m) limitations on certain covered employee compensation and state income taxes. No income tax expense was recorded for the three months ended June 30, 2022 because the entity was treated as a nontaxable partnership for income tax purposes for that period.
35
Results of Operations
Six Months Ended June 30, 2023 Compared with Six Months Ended June 30, 2022
The following table sets forth selected financial and operating data for the periods indicated.
| SIX MONTHS ENDED JUNE 30, | INCREASE (DECREASE) | ||||||||||||||||||||||
| ($ in thousands, except production and per unit data) | 2023 | 2022 | AMOUNT | PERCENT | |||||||||||||||||||
| Financial and Operating Results: | |||||||||||||||||||||||
| Revenue | |||||||||||||||||||||||
| Oil | $ | 99,219 | $ | 117,122 | $ | (17,903) | (15 | %) | |||||||||||||||
| Natural gas | 10,330 | 26,655 | (16,325) | (61 | %) | ||||||||||||||||||
| Total revenue | $ | 109,549 | $ | 143,777 | $ | (34,228) | (24 | %) | |||||||||||||||
| Operating Expenses | |||||||||||||||||||||||
| Lease operating expense | $ | 18,397 | $ | 14,159 | $ | 4,238 | 30 | % | |||||||||||||||
| Production taxes | 10,174 | 11,976 | (1,802) | (15 | %) | ||||||||||||||||||
| General and administrative | 15,323 | 6,507 | 8,816 | 135 | % | ||||||||||||||||||
| Depletion, depreciation, amortization, and accretion | 37,220 | 29,176 | 8,044 | 28 | % | ||||||||||||||||||
| Equity-based compensation | 29,400 | 22,240 | 7,160 | 32 | % | ||||||||||||||||||
| Interest Expense | $ | 2,295 | $ | 1,754 | $ | 541 | 31 | % | |||||||||||||||
| Commodity Derivative Gain (Loss), Net | $ | 12,198 | $ | (48,376) | $ | 60,574 | 125 | % | |||||||||||||||
| Income Tax Expense | $ | 47,183 | $ | — | $ | 47,183 | 100 | % | |||||||||||||||
| Production Data: | |||||||||||||||||||||||
| Oil (MBbls) | 1,389 | 1,198 | 191 | 16 | % | ||||||||||||||||||
| Natural gas (MMcf) | 4,089 | 3,378 | 711 | 21 | % | ||||||||||||||||||
| Combined volumes (MBoe) | 2,071 | 1,762 | 309 | 18 | % | ||||||||||||||||||
| Daily combined volumes (Boe/d) | 11,441 | 9,732 | 1,709 | 18 | % | ||||||||||||||||||
| Average Realized Prices before Hedging: | |||||||||||||||||||||||
| Oil (per Bbl) | $ | 71.42 | $ | 97.72 | $ | (26.30) | (27 | %) | |||||||||||||||
| Natural gas (per Mcf) | 2.53 | 7.89 | (5.36) | (68 | %) | ||||||||||||||||||
| Combined (per Boe) | 52.90 | 81.62 | (28.72) | (35 | %) | ||||||||||||||||||
| Average Realized Prices with Hedging: | |||||||||||||||||||||||
| Oil (per Bbl) | $ | 73.10 | $ | 73.05 | $ | 0.05 | 0 | % | |||||||||||||||
| Natural gas (per Mcf) | 2.53 | 7.72 | (5.19) | (67 | %) | ||||||||||||||||||
| Combined (per Boe) | 54.03 | 64.50 | (10.47) | (16 | %) | ||||||||||||||||||
| Average Costs (per Boe): | |||||||||||||||||||||||
| Lease operating | $ | 8.88 | $ | 8.04 | $ | 0.84 | 10 | % | |||||||||||||||
| Production taxes | 4.91 | 6.80 | (1.89) | (28 | %) | ||||||||||||||||||
| General and administrative | 7.40 | 3.69 | 3.71 | 101 | % | ||||||||||||||||||
| Depletion, depreciation, amortization, and accretion | 17.97 | 16.56 | 1.41 | 9 | % | ||||||||||||||||||
Oil and Natural Gas Revenue and Volumes. Oil and natural gas revenue decreased to $109.5 million for the six months ended June 30, 2023 from $143.8 million for the six months ended June 30, 2022. The decrease in oil and natural gas revenue was due to a 35% decrease in the average realized prices per Boe before hedging, which was partially offset by a 18% increase in production volumes for the six months ended June 30, 2023. The decrease in average realized prices per Boe before hedging decreased oil and natural gas revenue by approximately $50.6 million, while the increase in production volumes increased oil and natural gas revenue by approximately $16.4 million.
Our oil price differential to the weighted average WTI benchmark price during the six months ended June 30, 2023 was negative $3.45 per barrel, as compared to a negative $4.43 per barrel during the six months ended June 30, 2022, primarily due to favorable local market pricing as compared to the benchmark price. Our net realized natural gas price during the six months ended June 30, 2023 was $2.53 per Mcf, representing a 104% realization relative to weighted average Henry Hub pricing,
36
compared to a net realized natural gas price of $7.89 per Mcf during the six months ended June 30, 2022, representing a 130% realization relative to weighted average Henry Hub pricing. 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, 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 $8.88 per Boe for the six months ended June 30, 2023 from $8.04 per Boe for the six months ended June 30, 2022. The increase per Boe for the six months ended June 30, 2023 compared with the six months ended June 30, 2022 was related to higher workover and service costs. The increased workover costs were responsible for approximately $0.42/Boe of the increase and should result in increased production when these wells return to production.
Production Tax Expense. Total production taxes decreased to $10.2 million for the six months ended June 30, 2023 from $12.0 million for the six months ended June 30, 2022. 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 9.3% and 8.3% for the six months ended June 30, 2023 and 2022, respectively. The increase in the production tax rate for the six months ended June 30, 2023 was 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 $15.3 million for the six months ended June 30, 2023 from $6.5 million for the six months ended June 30, 2022. General and administrative expense on a per Boe basis increased to $7.40 for the six months ended June 30, 2023 from $3.69 for the six months ended June 30, 2022. The increase in general and administrative expense was primarily due to $5.9 million more Spin-Off costs incurred during the six months ended June 30, 2023 compared to six months ended June 30, 2022. Excluding costs related to the Spin-Off, the per Boe rate for the six months ended June 30, 2023 and 2022 would have been $4.11 and $3.20, 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 $37.2 million for the six months ended June 30, 2023 compared with $29.2 million for the six months ended June 30, 2022. The increase of $8.0 million, or 28%, was the result of a 18% increase in production and a $1.41/Boe increase in the DD&A rate for the six months ended June 30, 2023 compared with the six months ended June 30, 2022. The higher DD&A rate was driven by lower reserves due to lower oil and gas prices in 2023. The increase in production accounted for a $5.6 million increase in DD&A expense while the increase in the DD&A rate accounted for a $2.4 million increase in DD&A expense.
For the six months ended June 30, 2023, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate (excluding depreciation, amortization and accretion) of $17.82 per Boe compared with $16.45 per Boe for the six months ended June 30, 2022.
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 June 30, 2023, the Company granted 3,153,122 restricted stock units to employees and directors at a weighted-average grant date fair value of $14.47 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 $29.4 million for the six months ended June 30, 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 expense was $22.2 million for the six months ended June 30, 2022.
Interest Expense. Interest expense increased to $2.3 million for the six months ended June 30, 2023 from $1.8 million for the six months ended June 30, 2022. The increase for the six months ended June 30, 2023 was due to a higher SOFR interest rate in the six months ended June 30, 2023 despite the balance of debt outstanding declining to $41.0 million at June 30, 2023 from $84.0 million at June 30, 2022. The higher interest rate was due to increases to the federal funds rate by the Federal Reserve throughout 2022 and into the second quarter of 2023.
Commodity Derivative Gain (Loss), Net. The commodity derivative gain was $12.2 million for the six months ended June 30, 2023 compared with a loss of $48.4 million for the six months ended June 30, 2022. Gain (Loss) on Commodity Derivatives is
37
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.
The table below summarizes our commodity derivative gains and losses that were recorded in the periods presented.
| SIX MONTHS ENDED JUNE 30, | |||||||||||
| (in thousands) | 2023 | 2022 | |||||||||
Realized gain (loss) on commodity derivatives (1) | $ | 2,338 | $ | (30,154) | |||||||
Unrealized gain (loss) on commodity derivatives (1) | 9,860 | (18,222) | |||||||||
Total commodity derivative gain (loss) | $ | 12,198 | $ | (48,376) | |||||||
(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 statements of operations included in this Form 10-Q. 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 the six months ended June 30, 2023, approximately 50% of our oil volumes and none of our natural gas volumes were subject to financial hedges, which resulted in a realized gain on oil derivatives of $2.3 million. In the six months ended June 30, 2022, approximately 61% of our oil volumes and 13% of our natural gas volumes were covered by financial hedges, which resulted in a realized loss on oil derivatives of $29.6 million and a realized loss on natural gas derivatives of $0.6 million.
At June 30, 2023, all of our derivative contracts are recorded at their fair value, which was a net asset of $9.7 million, an increase of $9.9 million from the $0.2 million net liability recorded as of December 31, 2022. The increase was primarily due to changes to forward commodity prices relative to prices on our open commodity derivative contracts.
Income Tax Expense. During the six months ended June 30, 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. We recorded income tax expense of $3.1 million for the six months ended June 30, 2023 related to federal and state income taxes. The provision for income taxes for the six months ended June 30, 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 six months ended June 30, 2022 because the entity was treated as a nontaxable partnership for income tax purposes for that period.
Liquidity and Capital Resources
Overview. At June 30, 2023, we had $3.4 million of unrestricted cash on hand and $41.0 million of long-term debt. At December 31, 2022, we had $10.0 million of unrestricted cash on hand and $48.0 million of long-term debt. 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 June 30, 2023, we had a working capital deficit of $3.6 million, compared to a surplus of $17.7 million at December 31, 2022. Current assets decreased by $14.5 million while current liabilities increased by $6.7 million at June 30, 2023, compared to December 31, 2022. The decrease in current assets during the six months ended June 30, 2023 was primarily due to a decrease of $15.0 million in revenue receivable due to lower oil and natural gas revenue and the timing of revenue receipts from operators, and a decreased cash balance of $6.6 million, partially offset by an increase of $1.7 million in prepaid expenses and other current
38
assets related to income tax prepaid and receivable items and an increase of $5.3 million in our current commodity derivative instruments due to the change in fair value. The change in current liabilities during the six months ended June 30, 2023 was mostly due to an increase of $10.2 million in accounts payable and accrued liabilities as a result of increased development activity and a decrease of $3.4 million in current derivative instrument liabilities as a result of forward oil price decreases at June 30, 2023.
Cash Flows. Our cash flows for the six months ended June 30, 2023 and 2022 are presented below:
| SIX MONTHS ENDED JUNE 30, | |||||||||||
| (in thousands) | 2023 | 2022 | |||||||||
Cash flows provided by operating activities | $ | 78,243 | $ | 57,526 | |||||||
Cash flows used in investing activities | $ | (43,284) | $ | (39,826) | |||||||
Cash flows used in financing activities | $ | (41,606) | $ | (15,773) | |||||||
Net increase (decrease) in cash | $ | (6,647) | $ | 1,927 | |||||||
During the six months ended June 30, 2023, we generated $78.2 million of cash from operations, a 36% increase from the six months ended June 30, 2022. 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 its anticipated future oil and gas production for the next 12 to 24 months. See Part I, Item 3, “ 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 are required by certain debt covenants to partially mitigate through the use of commodity derivative contracts. As of June 30, 2023, we had oil swaps covering approximately 680,000 Bbls at a weighted average price of $77.95 per Bbl for remainder of calendar 2023 and oil swaps covering approximately 680,000 Bbls at a weighted average price of $76.00 per Bbl for calendar 2024. As of June 30, 2023, we had no natural gas derivative contracts. For more information on our outstanding derivatives, see Note 6 (“Derivative Instruments”) to the Condensed Consolidated Financial Statements.
Cash used in investing activities during the six months ended June 30, 2023 was $43.3 million compared to $39.8 million during the six months ended June 30, 2022. The $3.5 million increase was primarily related to increased development activity by our operators, partially offset by lower cash acquisitions. 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 acquisitions of near-term drilling opportunities when development activity by our operators on our existing properties lags behind our development objectives. Our cash spending for acquisition activities was $4.2 million and $18.4 million, during the six months ended June 30, 2023 and 2022, respectively.
Cash used in financing activities was $41.6 million and $15.8 million during the six months ended June 30, 2023 and 2022, respectively. The cash used in financing activities during the six months ended June 30, 2023 was related to $12.0 million of net repayments under our Revolving Credit Facility and $29.0 million in dividends paid. During the six months ended June 30, 2022, we borrowed $16.0 million under our Prior Revolving Credit Facility, which was offset by $30.0 million in distributions to our equity holders.
Prior Revolving Credit Facility. See Note 5 (“Credit Facility”) to the Condensed Consolidated Financial Statements 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
39
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.
See Note 5 (“Credit Facility”) to the Condensed Consolidated Financial Statements 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, quarterly dividends to our stockholders, our share repurchase program and other working capital needs. As commodity prices improve, our working capital requirements may increase as we spend additional capital, increase and maintain production and pay settlements on our outstanding commodity derivative contracts.
Our long-term material cash requirements from currently known obligations include anticipated repayment of outstanding borrowings and interest payment obligations under our Revolving Credit Facility, 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 Note 4 (“Fair Value Measurements”) to the Condensed Consolidated Financial Statements for further information on these contracts and their fair values as of June 30, 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 $29.0 million during the six months ended June 30, 2023. While we believe that our future cash flows from operations can 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 distributions to equity holders are subject to the terms of the Revolving Credit Facility, as previously described. There can be no guarantee that we will pay dividends or otherwise return capital to our stockholders in the future.
Capital Expenditures. For the six months ended June 30, 2023, total capital expenditures was $43.3 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. We cannot assure you, however, that any additional capital will be available to us on favorable terms or at all.
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 I. Item 3 Quantitative and Qualitative Disclosures About Market Risk.
Our recent capital commitments have been to fund acquisitions and development of oil and natural gas properties. We expect to fund our near-term capital requirements and working capital needs with cash flows from operations and available borrowing capacity under our Revolving Credit Facility. Our capital expenditures could be curtailed if our cash flows decline. Because production from existing oil and natural gas wells declines over time, reductions of capital expenditures used to drill and complete
40
new oil and natural gas wells would likely result in lower levels of oil and natural gas production in the future. Also, our obligations may change due to acquisitions, divestitures and continued growth. Our future success in growing proved reserves and production may be dependent on our ability to access outside sources of capital. If internally generated cash flow and borrowing capacity is not available under our Revolving Credit Facility, we may issue equity or debt securities to fund capital expenditures, acquisitions, extend maturities or to repay debt.
Effects of Inflation and Pricing. The oil and natural gas industry is very cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry put extreme 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 the first half of 2023 compared to 2022. 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 current 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 personnel. Despite these effects of inflation and pricing, we expect to continue generating significant amounts of free cash flow at current commodity price levels.
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.
Our critical accounting policies and estimates are described in “Critical Accounting Policies and Estimates” within Part II, Item 7 “Management's Discussion and Analysis of Financial Condition and Results of Operations” included in our Annual Report on Form 10-K for the year ended December 31, 2022. The critical accounting policies and estimates used in preparing our interim condensed consolidated financial statements for the three and six months ended June 30, 2023 are the same as those described in our Annual Report on Form 10-K for the year ended December 31, 2022.
A description of our significant accounting policies is included in Note 2 (“Significant Accounting Policies”) to the Condensed Consolidated Financial Statements set forth in Part I, Item 1.
Recently Issued or Adopted Accounting Pronouncements
For discussion of recently issued or adopted accounting pronouncements, see Note 2 (“Significant Accounting Policies”) to the Condensed Consolidated Financial Statements set forth in Part I, Item 1.
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.
41
Item 3. Quantitative and Qualitative Disclosure about Market Risk
Commodity Price Risk
The price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities, and, as a result, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand and other factors. Historically, the markets for oil and natural gas have been volatile, and we believe these markets will likely continue to be volatile in the future. The prices we receive for our production depend on numerous factors beyond our control. Our revenue generally would have increased or decreased along with any increases or decreases in oil or natural gas prices, but the exact impact on our income is indeterminable given the variety of expenses associated with producing and selling oil that also increase and decrease along with oil prices.
We enter into derivative contracts to achieve a more predictable cash flow by reducing our exposure to commodity price volatility. All derivative positions are carried at their fair value on the balance sheet and are marked-to-market at the end of each period. Any realized gains and losses on settled derivatives, as well as mark-to-market gains or losses, are aggregated and recorded to gain (loss) on derivative instruments, net on the statements of operations rather than as a component of other comprehensive income or other income (expense).
We generally use derivatives to economically hedge a significant, but varying portion of our anticipated future production. Any payments due to counterparties under our derivative contracts are funded by proceeds received from the sale of our production. Production receipts, however, lag payments to the counterparties. Any interim cash needs are funded by cash from operations or borrowings under our Revolving Credit Facility.
The following table summarizes our open crude oil swap contracts as of June 30, 2023, by fiscal quarter.
| SETTLEMENT PERIOD | OIL (barrels) | WEIGHTED AVERAGE PRICE $ | |||||||||
| Swaps-Crude Oil | |||||||||||
| 2023: | |||||||||||
| Q3 | 354,999 | $ | 78.25 | ||||||||
| Q4 | 324,998 | $ | 77.62 | ||||||||
| 2024: | |||||||||||
| Q1 | 199,998 | $ | 76.06 | ||||||||
| Q2 | 180,000 | $ | 75.97 | ||||||||
| Q3 | 180,000 | $ | 75.97 | ||||||||
| Q4 | 120,000 | $ | 75.97 | ||||||||
See Note 4 (“Fair Value Measurements”) and Note 6 (“Derivative Instruments”) to the Condensed Consolidated Financial Statements for further details regarding our commodity derivatives, including basis swap contracts for crude oil, which are not included in the foregoing tables.
Based upon our open commodity derivative positions at June 30, 2023, a hypothetical $1 increase or decrease in the NYMEX WTI strip price would increase or decrease our net commodity derivative position by approximately $1.3 million. The hypothetical change in fair value could be a gain or a loss depending on whether commodity prices decrease or increase.
Interest Rate Risk
Our long-term debt is composed of borrowings that contain floating interest rates. Our Revolving Credit Facility interest rate is a floating rate option that is designated by us within the parameters established by the underlying agreement. At our option, borrowings under the Revolving Credit Facility bear interest at either an adjusted forward-looking term rate based on SOFR (“Term SOFR”) or an adjusted base rate (“Base Rate”) (the highest of the administrative agent’s prime rate, the Federal Funds Rate plus 0.50% or the 30-day Term SOFR rate plus 1.0%), plus a spread ranging from 1.75% to 2.75% with respect to Base Rate borrowings and 2.75% to 3.75% with respect to Term SOFR borrowings, in each case based on the borrowing base utilization percentage. All outstanding principal is due and payable upon termination of the Revolving Credit Facility. Assuming no change in the amount outstanding, the impact on interest expense of a 1% increase or decrease in the average interest rate would be approximately $0.2 million increase or decrease in interest expense for the six months ended June 30, 2023.
42
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
In accordance with Rules 13a-15(b) of the Securities Exchange Act of 1934 (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of June 30, 2023. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of June 30, 2023 at the reasonable assurance level. Any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objective and management necessarily applies its judgment in evaluating the cost-benefit relationship of all possible controls and procedures.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act) that occurred during the second quarter of 2023 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
43
PART II – OTHER INFORMATION
Item 1. Legal Proceedings
From time to time we are subject to legal, administrative and environmental proceedings before various courts, arbitration panels and governmental agencies concerning claims arising in the ordinary course of business. These proceedings include certain contract disputes, additional environmental reviews and investigations, audits and pending judicial matters. Based on our current knowledge, we believe that the amount or range of reasonably possible losses will not, either individually or in the aggregate, materially adversely affect our business, financial condition and results of operations.
The results of any litigation cannot be predicted with certainty, and an unfavorable resolution in any legal proceedings could materially affect our business, financial condition and results of operations. Regardless of the outcome, litigation can have an adverse impact on us because of defense and settlement costs, diversion of management resources and other factors.
Item 1A. Risk Factors
There have been no material changes to the risk factors disclosed in Part I, Item 1A. Risk Factors, of our Annual Report on Form 10-K filed with the SEC for the period ended December 31, 2022.
Adverse developments affecting the financial services industry, such as actual events or concerns involving liquidity, defaults, or non-performance by financial institutions or transactional counterparties, could adversely affect our current and projected business operations and our financial condition and results of operations.
Actual events involving limited liquidity, defaults, non-performance or other adverse developments that affect financial institutions, transactional counterparties or other companies in the financial services industry or the financial services industry generally, or concerns or rumors about any events of these kinds or other similar risks, have in the past and may in the future lead to market-wide liquidity problems. For example, on March 10, 2023, Silicon Valley Bank (“SVB”) was closed by the California Department of Financial Protection and Innovation, which appointed the Federal Deposit Insurance Corporation (“FDIC”) as receiver. Similarly, on March 12, 2023, Signature Bank and Silvergate Capital Corp. and on May 1, 2023, First Republic Bank, were each swept into receivership. Although a statement by the Department of the Treasury, the Federal Reserve and the FDIC indicated that all depositors of SVB would have access to all of their money after only one business day of closure, including funds held in uninsured deposit accounts, borrowers under credit agreements, letters of credit and certain other financial instruments with SVB, Signature Bank, First Republic Bank or any other financial institution that is placed into receivership by the FDIC may be unable to access undrawn amounts thereunder. Although we do not have any funds deposited with SVB, Signature Bank and First Republic Bank, we currently, and may in the future, have assets held at financial institutions that may exceed the insurance coverage offered by the FDIC, and the loss of such assets would have a severe negative affect on our operations and liquidity. In addition, if any of our counterparties with whom we conduct business are unable to access funds pursuant to such instruments or lending arrangements with such a financial institution, such parties’ ability to pay their obligations to us or to enter into new commercial arrangements requiring additional payments to us could be adversely affected. Our primary banking relationship is with Wells Fargo Bank, as administrative agent and lender, and a syndicate of banks, as additional lenders under the Revolving Credit Facility including Fifth Third Bank, Bank of Oklahoma, and Amegy Bank.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Issuer Purchases of Equity Securities
In February 2023, our board of directors approved a Stock Repurchase Program authorizing the repurchase of up to $60 million of the Company’s common stock. Under the Stock Repurchase Program, Vitesse may repurchase shares of its common stock from time to time in open market transactions or such other means as will comply with applicable rules, regulations and contractual limitations. Our board of directors may limit or terminate the Stock Repurchase Program at any time without prior notice. The extent to which the Company repurchases its shares of common stock, and the timing of such repurchases, will depend upon market conditions and other considerations as may be considered in the Company’s sole discretion.
The table below sets forth the information with respect to purchases made by or on behalf of the Company, or any “affiliated purchaser” (as defined in Rule 10b-18(a)(3) under the Exchange Act) of our common stock during the three months ended June 30, 2023.
44
| Period | Total Number of Shares Purchased(1) | Average Price Paid Per Share | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(1) | Approximate Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs | ||||||||||||||||||||||
| April 1, 2023 to April 30, 2023 | — | $ | — | — | 59.8 | million | ||||||||||||||||||||
| May 1, 2023 to May 31, 2023 | — | — | — | 59.8 | million | |||||||||||||||||||||
| June 1, 2023 to June 30, 2023 | — | — | — | 59.8 | million | |||||||||||||||||||||
| Total | — | $ | — | — | $ | 59.8 | million | |||||||||||||||||||
(1) In February 2023, our board of directors approved a Stock Repurchase Program authorizing the repurchase of up to $60 million of the Company’s common stock.
Item 3. Defaults Upon Senior Securities
None.
Item 4. Mine Safety Disclosures
None.
Item 5. Other Information
During the three months ended June 30, 2023, no director or officer of the Company adopted, modified or terminated any “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement” within the meaning of Item 408(a) of Item 408 of Regulation S-K.
Item 6. Exhibits
| Exhibit No. | Description | Reference | ||||||||||||
| 3.1 | Incorporated by reference to Exhibit 3.1 to Form 8-K filed January 17, 2023, File No. 001-41546 | |||||||||||||
| 3.2 | Incorporated by reference to Exhibit 3.2 to Form 8-K filed January 17, 2023, File No. 001-41546 | |||||||||||||
| 10.1 | Incorporated by reference to Exhibit 10.3 to the Form 10-Q filed May 8, 2023, File No. 001-41546 | |||||||||||||
| 31.1 | Filed herewith. | |||||||||||||
| 31.2 | Filed herewith. | |||||||||||||
| 32.1 | Filed herewith. | |||||||||||||
| 101.INS | XBRL Instance Document | Formatted as Inline XBRL and contained in Exhibit 101. | ||||||||||||
| 101.SCH | XBRL Schema Document | Furnished herewith. | ||||||||||||
| 101.CAL | XBRL Calculation Linkbase Document | Furnished herewith. | ||||||||||||
| 101.LAB | XBRL Label Linkbase Document | Furnished herewith. | ||||||||||||
| 101.PRE | XBRL Presentation Linkbase Document | Furnished herewith. | ||||||||||||
| 101.DEF | XBRL Definition Linkbase Document | Furnished herewith. | ||||||||||||
| 104 | Cover Page Interactive Data File | Formatted as Inline XBRL and contained in Exhibit 101. | ||||||||||||
45
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacity and on the dates indicated:
| Signature | Title | Date | ||||||||||||
| /s/ Robert W. Gerrity | Chairman, Chief Executive Officer | July 31, 2023 | ||||||||||||
| Robert W. Gerrity | (Principal Executive Officer) | |||||||||||||
| /s/ David R. Macosko | Chief Financial Officer | July 31, 2023 | ||||||||||||
| David R. Macosko | (Principal Financial and Accounting Officer) | |||||||||||||
46