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  4. [8-K] Crescent Energy Co Reports Material Event

Crescent Energy to acquire Devon's Eagle Ford assets

Crescent identified approximately $140 million in annual synergies across drilling and completion, lease operating expenses and marketing.

Filing Impact
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Filing Sentiment

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Form Type
8-K

Rhea-AI Filing Summary

Crescent Energy Co (CRGY) said a subsidiary agreed to acquire Eagle Ford assets from Devon Energy Production Company for a contractual $4.22 billion cash purchase price, subject to customary adjustments. Crescent separately described an estimated net purchase price of approximately $3.85 billion after estimated purchase-price adjustments. Closing is expected in the fourth quarter of 2026 or early 2027, subject to customary conditions and regulatory approvals. A JPMorgan Chase Bank debt commitment letter includes a bridge facility of up to $2.0 billion, subject to customary terms and conditions.

The assets averaged approximately 71 net MBoe/d for the six months ended June 30, 2026. Crescent's portfolio data show 1,127.3 net MMBoe of proved reserves after giving effect to the acquisition as of December 31, 2025.

Unaudited pro forma results for the six months ended June 30, 2026, assuming the Devon acquisition and related financing had occurred on January 1, 2025, show $251.8 million of net income, $2.1 billion of Adjusted EBITDAX and $0.8 billion of Levered Free Cash Flow. For 2025, pro forma for the Vital Energy merger, Ridgemar acquisition, Devon acquisition and related financing, results show a $373.6 million net loss, $4.1 billion of Adjusted EBITDAX and $0.8 billion of Levered Free Cash Flow.

Filing Explained

The acquisition remains pending; although the purchase consideration is cash, Crescent says it intends to use cash on hand and, as market conditions warrant, debt and equity, leaving equity funding possible but no share issuance committed.

Item 1.01 Entry into a Material Definitive Agreement Business
The company signed a significant contract such as a merger agreement, credit facility, or major partnership.
Item 2.02 Results of Operations and Financial Condition Financial
Disclosure of earnings results, typically an earnings press release or preliminary financials.
Item 7.01 Regulation FD Disclosure Disclosure
Material non-public information disclosed under Regulation Fair Disclosure, often investor presentations or guidance.
Item 8.01 Other Events Other
Voluntary disclosure of events the company deems important to shareholders but not covered by other items.
Item 9.01 Financial Statements and Exhibits Exhibits
Financial statements, pro forma financial information, or exhibit attachments filed with this report.
Contractual purchase price $4.22 billion in cash Purchase agreement price, subject to customary adjustments
Estimated net purchase price approximately $3.85 billion Headline price less estimated purchase-price adjustments
Bridge credit facility up to $2.0 billion Debt commitment letter, subject to customary terms and conditions
Net production approximately 71 net MBoe/d Devon assets' average for the six months ended June 30, 2026
Proved reserves 1,127.3 net MMBoe Crescent portfolio after giving effect to the acquisition as of December 31, 2025
Annual synergies approximately $140 million Identified across drilling and completion, lease operating expenses and marketing
Adjusted EBITDAX financial
"generated $1.5 billion of Adjusted EBITDAX"
Adjusted EBITDAX is a measure of a company’s operating profit that adds back interest, taxes, depreciation, amortization and specific recurring costs (often exploration or similar project expenses), then removes one‑time or unusual items to show recurring cash profitability. Investors use it like a clean yardstick—ignoring financing choices, accounting rules and one‑off events—to compare core performance across periods or peers and assess a business’s ability to generate cash from operations.
Levered Free Cash Flow financial
"generated $609.5 million of Levered Free Cash Flow"
Levered free cash flow is the cash a company has left after paying all operating costs, taxes, interest and required debt repayments — essentially the money truly available to shareholders. For investors it matters because it shows whether a business can afford dividends, share buybacks, reinvestment or can weather a downturn after meeting its loan obligations; think of it like a household’s leftover money once the mortgage and other mandatory bills are paid.
PV-10 financial
"discounted at ten percent, or PV-10"
PV-10 is a valuation metric that estimates the present value of future oil and gas production cash flows, discounted at 10% and stated before income taxes. Think of it as the current price tag on a company’s proven reserves, calculated by shrinking future revenue streams to today’s dollars using a 10% rate. Investors use PV-10 to compare the relative worth of reserves and assess how much future production could contribute to a company’s value, much like comparing the upfront price of different rental properties based on expected future rent.
proved developed producing (PDP) reserves financial
"proved developed producing (“PDP”) reserves"
reinvestment rate financial
"reinvestment rate, which we define as our historical capital expenditures"

FAQ

AI-generated questions and answers. How Rhea-AI works. Not financial advice.

What is CRGY paying for the Devon assets?
The purchase agreement sets a $4.22 billion cash purchase price, while Crescent described an estimated net purchase price of approximately $3.85 billion. Crescent defines the net figure as the headline price less estimated purchase-price adjustments, including allocations of certain revenues and expenses based on a July 1, 2026 effective date.

When is CRGY's Devon acquisition expected to close?
Crescent expects the acquisition to close in the fourth quarter of 2026 or early 2027, subject to customary closing conditions and regulatory approvals.

AI-generated analysis. How Rhea-AI works. Not financial advice.

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0001866175False00018661752026-10-082026-10-08

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
________________________
FORM 8-K
________________________
CURRENT REPORT
PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934
Date of report (Date of earliest event reported): October 8, 2026
________________________
Crescent Energy Company
(Exact name of registrant as specified in its charter)
________________________
Delaware001-4113287-1133610
(State or other jurisdiction
of incorporation)
(Commission File Number)
(IRS Employer
Identification No.)
600 Travis Street, Suite 7200
Houston, Texas 77002
(address of principal executive offices) (zip code)
(713) 332-7001
(Registrant’s telephone number, including area code)
________________________
Check the appropriate box below if the Form 8-K is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
¨ Written communication pursuant to Rule 425 under the Securities Act of 1933 (17 CFR 230.425)
¨ Soliciting material pursuant to Rule 14a-12 under the Securities Exchange Act of 1934 (17 CFR 240.14a-12)
¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Securities Exchange Act of 1934 (17 CFR 240.14d-2(b))
¨ Pre-commencements communications pursuant to Rule 13e-4(c) under the Securities Exchange Act of 1934 (17 CFR 240.13e-4(c))
Securities registered pursuant to Section 12(b) of the Securities Exchange Act of 1934:
Title of Each Class
Trading Symbol(s)
Name of each exchange on which registered
Class A Common Stock, par value $0.0001 per shareCRGYThe New York Stock Exchange
Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).
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 Securities Exchange Act of 1934. ¨


Item 1.01.            Entry into a Material Definitive Agreement.
Devon EF Assets Acquisition Agreement
On October 8, 2026, a subsidiary of Crescent Energy Company (the “Company,” “Crescent,” “we,” “our” or “us”) entered into the Purchase and Sale Agreement (the “Devon EF Assets Acquisition Agreement”), pursuant to which we will acquire certain assets from Devon Energy Production Company, L.P., a subsidiary of Devon Energy Corporation (NYSE: DVN), (the “Devon EF Assets,” and such acquisition, the “Devon EF Assets Acquisition”) for a purchase price of $4,220,000,000 in cash. The purchase price will be subject to customary purchase price adjustments set forth in the Devon EF Assets Acquisition Agreement, including reductions for proceeds received from sales of hydrocarbons from the asset after the economic effective date of July 1, 2026. The Devon EF Assets Acquisition is structured as an all-cash transaction and is expected to close in the fourth quarter of 2026 or early 2027, subject to customary closing conditions and regulatory approvals.
In connection with the Devon EF Assets Acquisition, the Company obtained a debt commitment letter from JPMorgan Chase Bank, N.A. for, among other things and subject to the satisfaction of certain customary terms and conditions, a bridge credit facility in an aggregate amount of up to $2.0 billion on October 8, 2026.
Item 2.02.            Results of Operations and Financial Condition.
The information contained in Item 8.01 of this Current Report, to the extent required, is incorporated into this Item 2.02 by reference.
This Current Report provides (i) pro forma statements of operations of the Company for the year ended December 31, 2025 and for the six months ended June 30, 2026, giving effect to the Transactions (as defined below), as applicable, and the related financing transactions as if they had been consummated on January 1, 2025 and (ii) pro forma financial data as of June 30, 2026, giving effect to the Devon EF Assets Acquisition and the related financing transactions as if they had been consummated on June 30, 2026, in each case as described in Item 8.01 below and incorporated into this Item 2.02 by reference. The pro forma financial information gives effect to (i) the consummation of the acquisition of Vital Energy, Inc., a Delaware corporation (the “Vital Energy Merger”), as completed by the Company on December 15, 2025, (ii) the consummation of the acquisition of Ridgemar (Eagle Ford) LLC (the “Ridgemar Acquisition”) as completed by the Company on January 31, 2025, and (iii) the pending Devon EF Assets Acquisition (together with the Vital Energy Merger and the Ridgemar Acquisition, the “Transactions”).
The information contained in this Item 2.02 shall not be deemed to be “filed” for purposes of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), or otherwise subject to the liabilities of that section, and is not incorporated by reference into any filing under the Securities Act of 1933, as amended (the “Securities Act”), or the Exchange Act.
Item 7.01.         Regulation FD Disclosure.
On October 8, 2026, the Company issued a news release announcing the Devon EF Assets Acquisition. A copy of the press release is attached hereto as Exhibit 99.1 and incorporated herein by reference.
The information contained in this Item 7.01, including Exhibit 99.1, shall not be deemed to be “filed” for purposes of Section 18 of the Exchange Act, or otherwise subject to the liabilities of that section, and is not incorporated by reference into any filing under the Securities Act or the Exchange Act.
Item 8.01.            Other Events.
Recent Developments
On October 8, 2026, the Company provided certain updates to potential investors, the relevant excerpts of which are set forth below.
******
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Based on forecasts used in our reserve report and the Devon EF Assets reserve report, our proved developed producing (“PDP”) reserves as of December 31, 2025 have estimated average five-year and ten-year annual decline rates of approximately 12% and approximately 9%, respectively, and an estimated 2026 PDP decline rate of approximately 32%.
******
Our portfolio of assets:
•at December 31, 2025, consisted of 975.5 net MMBoe (or 1,127.3 net MMBoe after giving effect to the Devon EF Assets Acquisition) of proved reserves, of which approximately 61% were liquids (or 63% after giving effect to the Devon EF Assets Acquisition), reflecting $7.8 billion in standardized measure and $8.6 billion and $7.5 billion, respectively (or $11.0 billion and $8.9 billion,, respectively, after giving effect to the Devon EF Assets Acquisition), in net proved and net proved developed (“PD”) present value discounted at a 10% discount rate;
•during the year ended December 31, 2025, produced 260 net MBoe/d (or 316 MBoe/d after giving effect to the Devon EF Assets Acquisition) and during the six months ended June 30, 2026 produced 338 net MBoe/d (with the Devon EF Assets Acquisition to add production of approximately 71 net MBoe/d); and
•during the year ended December 31, 2025, generated $167.2 million of net income, $1.7 billion of net cash provided by operating activities, $2.1 billion of Adjusted EBITDAX and $856.1 million of Levered Free Cash Flow (or $373.6 million of net loss, $4.1 billion of Adjusted EBITDAX and $0.8 billion of Levered Free Cash Flow after giving effect to the Transactions and the related financing transactions), and during the six months ended June 30, 2026, generated $74.5 million of net income, $1.5 billion of Adjusted EBITDAX and $609.5 million of Levered Free Cash Flow (or $251.8 million of net income, $2.1 billion of Adjusted EBITDAX and $0.8 billion of Levered Free Cash Flow after giving effect to the Devon EF Assets Acquisition and the related financing transactions).
******
While many of our peers have historically outspent their cash flows, we have averaged a reinvestment rate, which we define as our historical capital expenditures (excluding acquisitions) over a specified period as a percentage of our historical Adjusted EBITDAX for such period, of approximately 45% of Adjusted EBITDAX since 2021.
******
The table below illustrates the aggregate reserve volumes associated with our proved assets as of December 31, 2025.
Operating AreaNet Acres
Net Proved Reserves (1)(4)
% Oil & Liquids (1)(4)
Net PD Reserves (1)(4)
2025 Total Net Production
SEC Net PD PV-10 (1)(2)(4)
NYMEX Net PD PV-10 (2)(5)(6)
(M)
(MMBoe)

(MMBoe)
(MBoe)
(MM)
(MM)
Working interest







Eagle Ford
532 537 56 %386 62,702 3,830 4,559 
Permian
336 350 69 %323 3,983 2,901 3,528 
Uinta
139 51 57 %37 8,530 444 553 
Total Working Interest, excluding Devon EF Assets(3)
1,019 950 61 %758 92,383 7,244 8,727 
Devon EF Assets(4)
89 152 79 %85 20,424 1,353 1,712 
Minerals and Royalties
443 26 59 %18 2,634 273 293 
Total
1,551 1,128 63 %861 115,441 8,870 10,732 
__________________
(1)Our reserves and present value (discounted at ten percent, or PV-10) were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. For oil and NGL volumes, the average WTI posted price of $65.34 per barrel as of December 31, 2025, was adjusted for items such as gravity, quality, local conditions, gathering, transportation fees and distance from
3

market. For natural gas volumes, the average Henry Hub Index spot price of $3.39 per MMBtu as of December 31, 2025, was similarly adjusted for items such as quality, local conditions, gathering, transportation fees and distance from market. All prices are held constant throughout the lives of the properties. The average adjusted realized product prices over the remaining lives of the properties are $64.42 per barrel of oil, $2.24 per Mcf of natural gas and $19.36 per barrel of NGLs.
(2)Reflects the net PD present values reflected in our and the Devon EF Assets’ respective proved reserve estimates as of December 31, 2025. PV-10 is not a financial measure prepared in accordance with GAAP because it does not include the effects of income taxes on future revenues. Our standardized measure totaled $7.8 billion as of December 31, 2025.
(3)Includes working interests in other basins not listed above; totals may not sum.
(4)The Devon EF Assets’ reserves and PV-10 were determined using SEC pricing. The 12-month 2025 average adjusted prices after differentials were $2.73 per Mcf of natural gas, $63.82 per barrel of oil, and $22.96 per barrel of NGL.
(5)Our NYMEX reserves and PV-10 were determined using index prices for oil and natural gas, respectively, without giving effect to derivative transactions and were calculated based on settlement prices to better reflect the market expectations as of that date, as adjusted for our estimates of quality, transportation fees, and market differentials. The NYMEX reserves calculations are based on NYMEX futures pricing at closing on September 30, 2026 for oil and natural gas. The average adjusted product prices over the remaining lives of the properties are $69.05 per barrel of oil, $2.37 per Mcf of natural gas and $20.42 per barrel of NGLs as of September 30, 2026 for Crescent Energy Company. We believe that the use of forward prices provides investors with additional useful information about our reserves, as the forward prices are based on the market’s forward-looking expectations of oil and natural gas prices as of a certain date, although we caution investors that this information should be viewed as a helpful alternative, not a substitute, for the data presented based on SEC pricing.
(6)The reserves, PV-0 and PV-10 associated with the Devon EF Assets were determined using NYMEX pricing, without giving effect to derivatives transactions and were calculated based on settlement prices to better reflect the market expectations as of that date, as adjusted for estimates of quality, transportation fees and market differentials. The NYMEX reserves calculations are based on NYMEX futures pricing at closing on September 30, 2026 for oil and natural gas. The average adjusted product prices over the remaining lives of the properties are $70.60 per barrel of oil, $3.30 per Mcf of natural gas and $25.88 per barrel of NGLs as of September 30, 2026 for the Devon EF Assets. We believe that the use of forward prices provides investors with additional useful information about reserves estimates, as the forward prices are based on the market’s forward-looking expectations of oil and natural gas prices as of a certain date, although we caution investors that this information should be viewed as a helpful alternative, not as a substitute, for the data presented based on SEC pricing.
******
As of December 31, 2025 and including the net drilling locations gained through the Devon EF Assets Acquisition, we have identified 358.5 net locations as PUD drilling locations.
******
The Devon EF Assets consist of an aggregate of approximately 89 thousand net acres (97% operated), with average net production for the year ended December 31, 2025 and for the six months ended June 30, 2026 of approximately 56 MBoe/d (65% oil-weighted) and 71 MBoe/d (63% oil-weighted). As of December 31, 2025, the proved developed reserves associated with the Devon EF Assets reflect $1.4 billion and $1.7 billion in net present value (discounted at ten percent, or PD PV-10) at SEC pricing as of December 31, 2025 and NYMEX pricing as of September 30, 2026, respectively.
******
We estimate the current run-rate production associated with the Devon EF Assets, as measured for the month of July 2026, to be 68 MBoe/d. Additionally, we now expect that, giving effect to the Devon EF Assets Acquisition, our capital expenditures (excluding acquisitions) for the year ending December 31, 2026 will be approximately $1.75 billion (assuming that the Devon EF Assets Acquisition had closed on January 1, 2026 and using the midpoint of our 2026 capital expenditures estimate). We determine our capital expenditures depending on a variety of factors, including, but not limited to, the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other working interest owners.
******
As of September 30, 2026, our derivative portfolio had an aggregate notional value of approximately $2.1 billion. We determine the fair value of our oil and natural gas commodity derivatives using valuation techniques that utilize market quotes and pricing analysis. Inputs include publicly available prices and forward price curves generated from a compilation of data gathered from third parties.
******
4

The following table details our net volume positions by commodity as of September 30, 2026.
Production PeriodVolumesWeighted Average
Fixed Price
(in thousands)
Crude oil swaps – WTI (Bbls):
20265,253 $64.62
20275,490 $62.40
2027 (1)
4,563 $73.92
Crude oil two-way collars – WTI (Bbls):
2026460 $60.00-$70.03
Crude oil three-way collars – WTI (Bbls):
20261,518 $48.00-$60.61-$74.98
20276,911 $52.87-$64.75-$81.37
2027 (2)
460 $45.00-$60.00-$70.00
Crude oil two-way collars – Brent (Bbls):
202646 $60.00-$82.00
Natural gas swaps (MMBtu):
202622,540 $4.10
20277,300 $4.21
2027 (3)
18,250 $4.19
Natural gas two-way collars (MMBtu):
202610,120 $3.04-$4.74
Crude oil basis swaps (Bbls):
20265,428 $1.34
20276,920 $1.48
Natural gas basis swaps (MMBtu):
202624,840 $(0.43)
202791,250 $(0.42)
Calendar Month Average roll swaps (Bbls):
20265,520 $0.56
Natural gas fixed index swaps – Waha (MMBtu):
202613,984 $2.41
202743,800 $2.69
_________________
(1)Represents outstanding crude oil swap options exercisable by the counterparty until December 2026 and June 2027.
(2)Represents outstanding crude oil three-way collar options exercisable by the counterparty until June 2027.
(3)Represents outstanding natural gas swap options exercisable by the counterparty until December 2026.
******
Summary reserve data based on NYMEX pricing
The following table provides our and the Devon EF Assets’ historical reserves, PV-0 and PV-10 as of December 31, 2025 using NYMEX pricing, individually and on a combined basis. We have included this reserve sensitivity in order to provide an additional method of presentation of the fair value of the assets and the cash flows that are expected to be generated from those assets based on the market’s forward-looking pricing expectations as of September 30, 2026. The historical 12-month average prices in our 2025 disclosures under the heading “—Summary reserve data based on SEC pricing” do not reflect the oil and natural gas futures. We believe that the use of forward prices provides investors with additional useful information about our reserves, as the forward prices are based on the market’s forward-looking expectations of oil and natural gas prices as of a certain date, although we caution investors that this information should be viewed as a helpful alternative, not a substitute, for the data presented based on SEC pricing. In addition, we believe strip pricing provides relevant and useful information because it is widely used by investors in our industry as a basis for comparing the relative size and value of proved reserves to our peers and in particular addresses the impact of differentials compared with our peers. Our and the
5

Devon EF Assets’ estimated historical reserves, PV-0 and PV-10 based on NYMEX pricing, were otherwise prepared on the same basis as our and the Devon EF Assets’ respective estimations based on SEC pricing reserves for the comparable period. Reserve estimates using NYMEX pricing are calculated using the internal systems of our management and have not been prepared or audited by an independent, third-party reserve engineer, but otherwise contain the same parameters, except for price and minor system differences.
As of December 31, 2025
Crescent(1)
Devon EF Assets(3)
Combined(4)
Net Proved Reserves:
Oil (MBbls)
359,671 87,125 446,796 
Natural gas (MMcf)
2,289,911 192,944 2,482,855 
NGLs (MBbls)
236,527 33,252 269,779 
Total Proved Reserves (MBoe)
977,850 152,535 1,130,385 
PV-0 (millions) (2)
$16,529 $4,052 $20,581 
PV-10 (millions) (2)
$10,487 $2,996 $13,483 
Net Proved Developed Reserves:



Oil (MBbls)
275,801 52,257 328,058 
Natural gas (MMcf)
1,831,072 96,077 1,927,149 
NGLs (MBbls)
197,760 17,169 214,929 
Total Proved Developed Reserves (MBoe)
778,740 85,439 864,179 
PV-0 (millions) (2)
$13,429 $2,270 $15,699 
PV-10 (millions) (2)
$9,020 $1,712 $10,732 
Net Proved Undeveloped Reserves:



Oil (MBbls)
83,870 34,868 118,738 
Natural gas (MMcf)
458,839 96,867 555,706 
NGLs (MBbls)
38,767 16,083 54,850 
Total Proved Undeveloped Reserves (MBoe)
199,110 67,096 266,206 
PV-0 (millions) (2)
$3,100 $1,782 $4,882 
PV-10 (millions) (2)
$1,467 $1,284 $2,751 
__________________
(1)Our NYMEX reserves, PV-0 and PV-10 were determined using NYMEX pricing, without giving effect to derivative transactions and were calculated based on settlement prices to better reflect the market expectations as of that date, as adjusted for our estimates of quality, transportation fees, and market differentials. The NYMEX reserves calculations are based on NYMEX pricing at closing on September 30, 2026 for oil and natural gas. The average adjusted product prices over the remaining lives of the properties are $69.05 per barrel of oil, $2.37 per Mcf of natural gas and $20.42 per barrel of NGLs as of September 30, 2026 for Crescent Energy Company. We believe that the use of forward prices provides investors with additional useful information about our reserves, as the forward prices are based on the market’s forward-looking expectations of oil and natural gas prices as of a certain date, although we caution investors that this information should be viewed as a helpful alternative, not as a substitute, for the data presented based on SEC pricing.
(2)Present value (discounted at PV-0 and PV-10) is not a financial measure calculated in accordance with GAAP because it does not include the effects of income taxes on future net revenues. Neither PV-0 nor PV-10 represent an estimate of the fair market value of our oil and natural gas properties. Our PV-0 measurement does not provide a discount rate to estimated future cash flows. PV-0 therefore does not reflect the risk associated with future cash flow projections like PV-10 does. PV-0 should therefore only be evaluated in connection with an evaluation of our PV-10 of discounted future net cash flows. We believe that the presentation of PV-0 and PV-10 is relevant and useful to our investors about the future net cash flows of our reserves in the absence of a comparable measure such as standardized measure. We and others in our industry use PV-0 and PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. Investors should be cautioned that neither of PV-0 and PV-10 represent an estimate of the fair market value of our proved reserves. GAAP does not prescribe any corresponding measure for PV-10 of reserves based on pricing other than SEC pricing. As a result, it is not practicable for us to reconcile our PV-10 using NYMEX pricing to standardized measure as determined in accordance with GAAP.
(3)The reserves, PV-0 and PV-10 associated with the Devon EF Assets were determined using NYMEX pricing, without giving effect to derivative transactions and were calculated based on settlement prices to better reflect the market expectations as of that date. The NYMEX reserves calculations are based on NYMEX pricing at closing on September 30, 2026 for oil and natural gas. The average adjusted product prices over the remaining lives of the properties are $70.60 per barrel of oil, $3.30 per Mcf of natural gas and $25.88 per barrel of NGLs as of September 30, 2026 for the Devon EF Assets. We believe that the use of forward prices provides investors with additional useful
6

information about reserves estimates, as the forward prices are based on the market’s forward-looking expectations of oil and natural gas prices as of a certain date, although we caution investors that this information should be viewed as a helpful alternative, not as a substitute, for the data presented based on SEC pricing.
(4)Pro forma reserve data generally represents the arithmetic sum of the proved reserves, the standardized measure, PV-0 and PV-10 attributable to Crescent Energy Company and the Devon EF Assets. The proved reserves of the Devon EF Assets are based on its development plan and its reserve engineer’s reserve estimation methodologies. Because we will develop such proved reserves in accordance with our own development plan and, in the future, will estimate proved reserves in accordance with our own methodologies, the estimates presented herein for the Devon EF Assets may not be representative of our future reserve estimates with respect to these properties or the reserve estimates we would have reported if we had owned such properties as of December 31, 2025.
******
Pro Forma
The information contained in Item 9.01(b) of this Current Report on Form 8-K is incorporated into this Item 8.01 by reference.
Devon EF Assets Reserve Report
This Item 8.01 also incorporates by reference the information contained in Item 2.02 of this Current Report and the reserve report prepared by DeGolyer and MacNaughton, independent reserve engineer, with respect to the Devon EF Assets, filed as Exhibit 99.2 herewith.
Item 9.01.         Financial Statements and Exhibits.
(a)Financial Statements of Business Acquired
Vital Energy Merger
The following historical financial statements of the business acquired in the Vital Energy Merger, attached as Exhibit 99.3 hereto:
•the historical audited consolidated financial statements of Vital Energy, Inc. as of December 31, 2024 and 2023 and for each of the three years ended December 31, 2024, 2023 and 2022;
•the historical unaudited consolidated financial statements of Vital Energy, Inc. as of September 30, 2025 and for the three and nine months ended September 30, 2025 and 2024; and
•notes to the consolidated financial statements.
Devon EF Assets Acquisition
The following historical financial statements of the business to be acquired in the Devon EF Assets Acquisition, attached as Exhibit 99.4 hereto:
•the historical audited statement of revenues and direct operating expenses for the Devon EF Assets for the years ended December 31, 2025 and 2024;
•the historical unaudited statement of revenues and direct operating expenses for the Devon EF Assets for the six months ended June 30, 2026 and 2025; and
•notes to the financial statements.
(b)Pro Forma Financials
This Current Report provides the unaudited pro forma condensed combined financial statements of the Company, giving effect to the Transactions and the related financing transactions, attached as Exhibit 99.5 hereto:
•Unaudited Pro Forma Condensed Combined Statement of Operations for the year ended December 31, 2025;
7

•Unaudited Pro Forma Condensed Combined Statement of Operations for the six months ended June 30, 2026;
•Unaudited Pro Forma Condensed Combined Balance Sheet as of June 30, 2026; and
•Notes to the Unaudited Pro Forma Condensed Combined Financial Statements.
Pro forma financial data for the year ended December 31, 2025 gives effect to the Transactions and the related financing transactions as if they had been consummated on January 1, 2025. Pro forma financial data for the six months ended June 30, 2026 gives effect to the pending Devon EF Assets Acquisition and the related financing transactions as if they had been consummated on January 1, 2025. Pro forma financial data as of June 30, 2026 gives effect to the Devon EF Assets Acquisition and the related financing transactions as if they had been consummated on June 30, 2026.
(d)Exhibits
Exhibit No.Description
23.1
Consent of Ernst & Young LLP (Vital Energy, Inc.).
23.2
Consent of DeGolyer & MacNaughton (Devon EF Assets).
23.3
Consent of KPMG LLP (Devon EF Assets).
99.1
Press Release Announcing the Devon EF Assets Acquisition, dated October 8, 2026.
99.2
Report of DeGolyer & MacNaughton (Devon EF Assets).
99.3
Historical audited consolidated financial statements of Vital Energy, Inc. as of December 31, 2024 and 2023 and for each of the three years ended December 31, 2024, 2023 and 2022 and historical unaudited consolidated financial statements of Vital Energy, Inc. as of September 30, 2025 and for the three and nine months ended September 30, 2025 and 2024.
99.4
Historical audited statement of revenues and direct operating expenses for the Devon EF Assets for the years ended December 31, 2025 and 2024 and the historical unaudited statement of revenues and direct operating expenses for the Devon EF Assets for the six months ended June 30, 2026 and 2025.
99.5
Unaudited pro forma condensed combined financial statements as of June 30, 2026 and for the six months ended June 30, 2026 and for the year ended December 31, 2025.
104Cover Page Interactive Data File (embedded within Inline XBRL document).
8

SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
CRESCENT ENERGY COMPANY
Date: October 8, 2026
By:
/s/ Bo Shi
Name:
Bo Shi
Title:
General Counsel
9
Exhibit 99.1
Crescent Energy to Acquire Eagle Ford Assets from Devon Energy,
Solidifying Crescent’s World-Class Position in the Basin
High-margin, oil-weighted production and significant Tier 1 inventory adjacent to existing operations
Attractive acquisition returns and meaningful accretion across all key metrics
Devon-owned minerals add significant scale and increased operatorship to Crescent Royalties
HOUSTON, October 8, 2026 – Crescent Energy Company (NYSE: CRGY) (“Crescent” or the “Company”) today announced that it has entered into a definitive agreement to acquire Eagle Ford assets from Devon Energy for an estimated net purchase price of approximately $3.85 billion(1) (the “Transaction”). The Transaction solidifies Crescent’s world-class Eagle Ford position, adding Tier 1 inventory and meaningful scale directly adjacent to its existing operations. The acquired assets will be managed with Crescent’s consistent strategy focused on free cash flow, disciplined capital allocation and attractive returns. The Transaction is expected to close in the fourth quarter of 2026 or early 2027, subject to customary closing conditions.
The acquired assets include approximately 68 Mboe/d of net production(2) and more than 600 Tier 1 net locations normalized to 10,000 feet. Crescent’s longstanding minerals ownership across the acquired assets, nearby operations and deep technical knowledge provide differentiated insight and conviction in the assets.
The Transaction Offers Compelling Value for All Shareholders:
–Solidifies Crescent’s World-Class Eagle Ford Position – Significant Tier 1 inventory in the Karnes Trough that immediately competes for capital; assets directly adjacent to Crescent’s existing operations further enhance Crescent’s basin-leading position and build on its established operating and minerals footprint.
–Compelling Returns and Accretion – Strong investment returns, in-line with Crescent’s consistent underwriting criteria and meaningful accretion across all key metrics, including CFFO, FCF and NAV.
–Accelerates Crescent’s Value Creation – Higher quality inventory, improved capital efficiency and increased margins enhance free cash flow generation. Applying Crescent’s proven “buy assets and make them better” operating playbook, with approximately $140 million in annual synergies identified across D&C, LOE and marketing.
–Transforms Market-Leading Royalties Platform – Devon-owned minerals strengthen Crescent Royalties through greater scale, increased operatorship and enhanced development visibility.
–Maintains Strong Balance Sheet and Progress Toward Investment Grade – Balanced financing structure, greater scale and strong free cash flow generation support debt reduction and continued progress toward an investment-grade credit profile.
“This acquisition represents a significant step forward for Crescent, adding high-quality assets at an attractive valuation in the heart of one of our core operating areas,” said David Rockecharlie, Chief Executive Officer of Crescent Energy. “We know these assets exceptionally well through our longstanding minerals ownership and nearby operations, and see meaningful opportunity to make them even better. The transaction solidifies Crescent’s world-class Eagle Ford position and creates significant additional value creation opportunities through our proven operating strategy.”

Transaction Financing
1

Crescent has obtained commitments for certain debt financing options from JPMorgan Chase Bank, N.A. and RBC Capital Markets, LLC in connection with this transaction. KKR Capital Markets also advised on the financing. The Company intends to fund the transaction consideration through a combination of cash on hand, and, as appropriate, based on market conditions, a balanced mix of debt and equity. There can be no guarantee that additional financing will be available on terms satisfactory to the Company or at all.
Advisors
Crescent’s financial advisors in connection with the acquisition are Jefferies LLC and J.P. Morgan Securities LLC. Crescent’s counsel is Latham & Watkins LLP and Vinson & Elkins LLP. RBC Capital Markets, LLC served as financial advisor to Devon Energy, and Kirkland & Ellis LLP served as legal counsel.
Conference Call Details
Crescent plans to host a conference call and webcast at 7:00 a.m. Central Time / 8:00 a.m. Eastern Time on October 8, 2026. Complete details are below.
Date: Thursday, October 8, 2026
Time: 7:00 a.m. CT (8:00 a.m. ET)
Conference Dial-In: 833-461-5787 / 585-542-9983 (Domestic / International)
Meeting ID: 542 556 661
Webcast Link: www.crescentenergyco.com
An investor presentation regarding the transaction can be found at www.crescentenergyco.com. A webcast replay will be available on the website following the call.
About Crescent Energy Company
Crescent is a differentiated energy company committed to delivering value through a disciplined, returns-driven growth through acquisition strategy and consistent return of capital. Our long-life, balanced portfolio combines significant cash flow from stable production with deep, high-quality development inventory. Our activities are focused in the Eagle Ford, Permian and Uinta Basins, and we own minerals and royalty interests across premier U.S. oil and natural gas basins, primarily operated by large, well-capitalized companies, with a core focus in the Eagle Ford. For additional information, please visit www.crescentenergyco.com.
Forward-Looking Statements and Cautionary Statements
The foregoing contains “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical fact, included in this communication that address activities, events or developments that Crescent expects, believes or anticipates will or may occur in the future are forward-looking statements. Words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “create,” “intend,” “could,” “may,” “foresee,” “plan,” “will,” “guidance,” “look,” “outlook,” “goal,” “future,” “assume,” “forecast,” “build,” “focus,” “work,” “continue” or the negative of such terms or other variations thereof and words and terms of similar substance used in connection with any discussion of future plans, actions, or events identify forward-looking statements. However, the absence of these words does not mean that the statements are not forward-looking. These forward-looking statements include, but are not limited to, statements regarding the Transaction, the expected timing of completion of the Transaction, pro forma descriptions of the combined company and its operations, integration and transition plans, synergies, opportunities and anticipated future performance and anticipated financing plans relating to the Transaction. There are a number of risks and uncertainties that could cause actual
2
Classification: Limited

results to differ materially from the forward-looking statements included in this communication. These include the expected timing and likelihood of completion of the Transaction, including the timing, receipt and terms and conditions of any required governmental and regulatory approvals of the Transaction that could reduce anticipated benefits or cause the parties to abandon the Transaction, the ability to successfully integrate the businesses, the availability of financing relating to the purchase price of the Transaction on terms satisfactory to the Company or at all, the risk that the parties may not be able to satisfy the conditions to the Transaction in a timely manner or at all, risks related to disruption of management time from ongoing business operations due to the Transaction, the risk that any announcements relating to the Transaction could have adverse effects on the market price of Crescent’s common stock, the risk that problems may arise in successfully integrating the assets, which may result in the combined company not operating as effectively and efficiently as expected, the risk that the combined company may be unable to achieve synergies or it may take longer than expected to achieve those synergies and other important factors that could cause actual results to differ materially from those projected. All such factors are difficult to predict and are beyond Crescent’s control, including those detailed in Crescent’s annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K that are available on its website at www.crescentenergyco.com and on the SEC’s website at http://www.sec.gov. The Company does not give any assurance (1) that it will achieve its expectations or (2) as to any business strategies, earnings or revenue trends or future financial results. All forward-looking statements are based on assumptions that Crescent believes to be reasonable but that may not prove to be accurate. Any forward-looking statement speaks only as of the date on which such statement is made and Crescent undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. Readers are cautioned not to place undue reliance on these forward-looking statements that speak only as of the date hereof.
Crescent Energy Investor Relations Contact
IR@crescentenergyco.com
Crescent Energy Media Contact
Media@crescentenergyco.com
(1)Net purchase price is defined as headline purchase price less estimated purchase price adjustments, including, among other things, allocations of certain revenues and expenses based on a July 1, 2026 effective date.
(2)Represents July 2026 net production from internal forecast.
3
Classification: Limited
Exhibit 99.2
DeGolyer and MacNaughton
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244
October 7, 2026
Crescent Energy Company
600 Travis Street
Suite 7200
Houston, Texas 77002
Ladies and Gentlemen:
Pursuant to your request, this report of third party presents an independent evaluation, as of December 31, 2025, of the extent and value of the estimated net proved oil, condensate, natural gas liquids (NGL), and gas reserves of certain properties in which Crescent Energy Company (Crescent) has represented Devon Energy Corporation (Devon) holds an interest. The properties evaluated consist of working and royalty interests located in the Eagle Ford Shale in Texas. This evaluation is associated with Crescent’s potential acquisition of Devon’s interest in the evaluated Eagle Ford Shale properties. This evaluation was completed on
October 7, 2026. Crescent has represented that these properties account for 100 percent on a net equivalent barrel basis of the net proved reserves to be potentially acquired from Devon, as of December 31, 2025. The net proved reserves estimates have been prepared in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the United States Securities and Exchange Commission (SEC). This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S–K and is to be used for inclusion in certain SEC filings by Crescent.
Reserves estimates included herein are expressed as net reserves. Gross reserves are defined as the total estimated petroleum remaining to be produced from these properties after December 31, 2025. Net reserves are defined as that portion of the gross reserves attributable to the interests held by Devon after deducting all interests held by others.
Values for proved reserves in this report are expressed in terms of future gross revenue, future net revenue, and present worth. Future gross revenue is defined as
that revenue which will accrue to the evaluated interests from the production and sale of the estimated net reserves. Future net revenue is calculated by deducting production taxes, ad valorem taxes, operating expenses, capital costs, and abandonment costs from future gross revenue. Operating expenses include field operating expenses, transportation and processing expenses, and an allocation of overhead that directly relates to production activities. Capital costs include drilling and completion costs, facilities costs, and field maintenance costs. Abandonment costs are represented by Crescent to be inclusive of those costs associated with the removal of equipment, plugging of wells, and reclamation and restoration associated with the abandonment. At the request of Crescent, future income taxes were not taken into account in the preparation of these estimates. Present worth is defined as future net revenue discounted at a discount rate of 10 percent per year compounded monthly over the expected period of realization. Present worth should not be construed as fair market value because no

2
DeGolyer and MacNaughton
consideration was given to additional factors that influence the prices at which properties are bought and sold.
Estimates of reserves and revenue should be regarded only as estimates that may change as further production history and additional information become available. Not only are such estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.
This report was prepared in October 2026; therefore, certain events that may have occurred before the preparation of this report but after the “as-of” date of December 31, 2025, which might have affected the estimates presented herein, were not taken into account.
Information used in the preparation of this report was obtained from Devon and from public sources. In the preparation of this report we have relied, without independent verification, upon information furnished by Devon with respect to the property interests being evaluated, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination was not considered necessary for the purposes of this report.
Definition of Reserves
Petroleum reserves included in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used in this report are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using established production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:
Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and 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.
(i) The area of the reservoir considered as proved includes:
(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically

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DeGolyer and MacNaughton
producible oil or gas on the basis of available geoscience and engineering data.
(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.
(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Undeveloped oil and gas reserves – Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

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DeGolyer and MacNaughton
(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
(ii) 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, unless the specific circumstances justify a longer time.
(iii) Under no circumstances shall estimates for 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, as defined in [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.
Methodology and Procedures
Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC and with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (revised June 2019) Approved by the SPE Board on 25 June 2019” and in Monograph 3 and Monograph 4 published by the Society of Petroleum Evaluation Engineers. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.
Based on the current stage of field development, production performance, the development plan provided by Devon, and analyses of areas offsetting existing wells with test or production data, reserves were classified as proved. The proved undeveloped reserves were based on opportunities identified in the plan of development provided by Devon.
Devon has represented that its senior management is committed to the development plan and that Devon has the financial capability to execute the development plan, including the drilling and completion of wells and the installation of equipment and facilities.
For the evaluation of unconventional reservoirs, a performance-based methodology integrating the appropriate geology and petroleum engineering data was utilized for this report. Performance-based methodology primarily includes (1) production diagnostics, (2) decline-curve analysis, and (3) model-based analysis (if necessary, based on availability of data). Production diagnostics include data quality control, identification of flow regimes, and characteristic well performance behavior. These analyses were performed for all well groupings (or type-curve areas).
Characteristic rate-decline profiles from diagnostic interpretation were translated to modified hyperbolic rate profiles, including one or multiple b-exponent values followed by an

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DeGolyer and MacNaughton
exponential decline. Based on the availability of data, model-based analysis may be integrated to evaluate long-term decline behavior, the effect of dynamic reservoir and fracture parameters on well performance, and complex situations sourced by the nature of unconventional reservoirs.
In the evaluation of undeveloped reserves, type-well analysis was performed using well data from analogous reservoirs for which more complete historical performance data were available.
Data provided by Devon from wells drilled through December 31, 2025, and made available for this evaluation were used to prepare the reserves estimates herein. These reserves estimates were based on consideration of daily and monthly production data available through December 2025. Cumulative production, as of December 31, 2025, was deducted from the estimated gross ultimate recovery to estimate gross reserves.
Oil and condensate reserves estimated herein are to be recovered by normal field separation. NGL reserves estimated herein include pentanes and heavier fractions (C5+) and liquefied petroleum gas (LPG), which consists primarily of propane and butane fractions, and are the result of low-temperature plant processing. Oil, condensate, and NGL reserves included in this report are expressed in thousands of barrels (Mbbl). In these estimates, 1 barrel equals 42 United States gallons. For reporting purposes, oil and condensate reserves have been estimated separately and are presented herein as a summed quantity.
Gas quantities estimated herein are expressed as sales gas. Sales gas is defined as the total gas to be produced from the reservoirs, measured at the point of delivery, after reduction for fuel usage, flare, and shrinkage resulting from field separation and processing. Gas reserves estimated herein are reported as sales gas. Gas quantities are expressed at a temperature base of 60 degrees Fahrenheit (°F) and at the pressure base of the state in which the quantities are located. Gas quantities included in this report are expressed in millions of cubic feet (MMcf).
Gas quantities are identified by the type of reservoir from which the gas will be produced. Nonassociated gas is gas at initial reservoir conditions with no oil present in the reservoir. Associated gas is both gas-cap gas and solution gas. Gas-cap gas is gas at initial reservoir conditions and is in communication with an underlying oil zone. Solution gas is gas dissolved in oil at initial reservoir conditions. Gas quantities estimated herein include both associated and nonassociated gas.
At the request of Crescent, sales gas reserves estimated herein were converted to oil equivalent using an energy equivalent factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent.
Primary Economic Assumptions
Revenue values in this report were estimated using initial prices, expenses, and costs provided by Devon. Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The following economic assumptions were used for estimating the revenue values reported herein:
Oil, Condensate, and NGL Prices
Devon has represented that the oil, condensate, and NGL prices were based on a reference price, calculated as the unweighted arithmetic

6
DeGolyer and MacNaughton
average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual agreements. Devon supplied differentials to a West Texas Intermediate (WTI) reference price of $65.34 per barrel and the prices were held constant thereafter. The volume-weighted average prices attributable to the estimated proved reserves over the lives of the properties were $63.82 per barrel of oil and condensate and $22.96 per barrel of NGL.
Gas Prices
Devon has represented that the gas prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual agreements. Devon supplied differentials to a Henry Hub reference price of $3.39 per million Btu ($/MMBtu) and the prices were held constant thereafter. Btu factors provided by Devon were used to convert prices from dollars per million Btu to dollars per thousand cubic feet. The volume-weighted average price attributable to the estimated proved reserves over the lives of the properties was $2.731 per thousand cubic feet of gas.
Production and Ad Valorem Taxes
Production taxes were calculated using the tax rates for Texas. Ad valorem taxes were calculated using rates provided by Devon based on recent payments.
Operating Expenses, Capital Costs, and Abandonment Costs
Estimates of operating expenses, provided by Devon and based on existing economic conditions, were held constant for the lives of the properties. Future capital expenditures were estimated using 2025 values, provided by Devon, and were not adjusted for inflation. In certain cases, future expenditures, either higher or lower than current expenditures, may have been used because of anticipated changes in operating conditions, but no general escalation that might result from inflation was applied. Abandonment costs, which are those costs associated with the removal of equipment, plugging of wells, and reclamation and restoration associated with the abandonment, were provided by Devon for all properties and were not adjusted for inflation. Operating expenses, capital costs, and abandonment costs were considered, as appropriate, in determining the economic viability of the undeveloped reserves estimated herein.
In our opinion, the information relating to estimated proved reserves, estimated future net revenue from proved reserves, and present worth of estimated future net revenue from proved reserves of oil, condensate, NGL, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, 932-235-50-9, 932-235-50-30, and 932-235-50-31(a), (b), and (e) of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation

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DeGolyer and MacNaughton
and Disclosures (January 2010) of the FASB and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (8), and 1203(a) of Regulation S–K of the SEC; provided, however, that (i) future income tax expenses have not been taken into account in estimating the future net revenue and present worth values set forth herein and (ii) estimates of the proved developed and proved undeveloped reserves are not presented at the beginning of the year.
To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.
Summary of Conclusions
DeGolyer and MacNaughton has performed an independent evaluation of the extent and value of the estimated net proved oil, condensate, NGL, and gas reserves of certain properties in which Crescent has represented Devon holds an interest. The estimated net proved reserves, as of December 31, 2025, of the properties evaluated herein were based on the definition of proved reserves of the SEC and are summarized as follows, expressed in thousands of barrels (Mbbl), millions of cubic feet (MMcf), and thousands of barrels oil equivalent (Mboe):

Estimated by DeGolyer and MacNaughton
Net Proved Reserves
as of December 31, 2025
Properties Evaluated by DeGolyer and MacNaughton

Oil and Condensate
(Mbbl)

NGL
(Mbbl)

Sales
Gas
(MMcf)

Oil
Equivalent
(Mbbl)
Proved Developed

50,594 

16,419 

91,856 

82,322 
Proved Undeveloped

34,838 

16,048 

96,632 

66,991 
Total Proved

86,894 

33,011 

191,484 

151,819 
Note: Sales gas reserves estimated herein were converted to oil equivalent using an energy equivalent factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent.
The estimated future revenue to be derived from the production and sale of the net proved reserves, as of December 31, 2025, of the properties evaluated using the guidelines established by the SEC is summarized as follows, expressed in thousands of dollars (M$):


Proved
Developed
(M$)

Total
Proved
(M$)
Future Gross Revenue

3,989,875 

6,826,471 
Production and Ad Valorem Taxes

250,396 

446,214 
Operating Expenses

1,670,682 

2,092,368 
Capital and Abandonment Costs

194,814 

977,661 
Future Net Revenue

1,873,983 

3,310,228 
Present Worth at 10 Percent

1,352,534 

2,340,030 





Note: Future income taxes have not been taken into account in the preparation of these estimates.
Dilhan Ilk
Dilhan Ilk, P.E.
[SEAL]Executive Vice President
DeGolyer and MacNaughton
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DeGolyer and MacNaughton
While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2025, estimated reserves.
DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in Crescent. Our fees were not contingent on the results of our evaluation. This report has been prepared at the request of Crescent. DeGolyer and MacNaughton has used all assumptions, procedures, data, and methods that it considers necessary and appropriate to prepare this report.
Submitted,
DeGOLYER and MacNAUGHTON
Texas Registered Engineering Firm F-716
Dilhan Ilk
Dilhan Ilk, P.E.
[SEAL]Executive Vice President
DeGolyer and MacNaughton
DeGolyer and MacNaughton
CERTIFICATE of QUALIFICATION
I, Dilhan Ilk, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:
1.That I am an Executive Vice President with DeGolyer and MacNaughton, which firm did prepare the report of third party addressed to Crescent dated October 7, 2026, and that I, as Executive Vice President, was responsible for the preparation of this report of third party.
2.That I attended Istanbul Technical University, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 2003, a Master of Science degree in Petroleum Engineering from Texas A&M University in 2005, and a Doctor of Philosophy degree in Petroleum Engineering from Texas A&M University in 2010; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers; and that I have in excess of 16 years of experience in oil and gas reservoir studies and reserves evaluations.
Dilhan Ilk
Dilhan Ilk, P.E.
[SEAL]Executive Vice President
DeGolyer and MacNaughton
Exhibit 99.3
Part I

Item 1.    Consolidated Financial Statements (Unaudited)

Vital Energy, Inc.
Consolidated balance sheets
(in thousands, except share data)
(Unaudited)
September 30, 2025December 31, 2024
Assets
Current assets:
Cash and cash equivalents$14,697 $40,179 
Accounts receivable, net227,747 299,698 
Derivatives149,332 101,474 
Other current assets29,276 25,205 
Total current assets421,052 466,556 
Property and equipment:
Oil and natural gas properties, full cost method:
Evaluated properties14,429,480 13,587,040 
Unevaluated properties not being depleted132,800 242,792 
Less: accumulated depletion and impairment(10,509,728)(8,966,200)
Oil and natural gas properties, net4,052,552 4,863,632 
Midstream and other fixed assets, net121,050 134,265 
Property and equipment, net4,173,602 4,997,897 
Derivatives20,960 34,564 
Operating lease right-of-use assets65,669 104,329 
Deferred income taxes5,971 239,685 
Other noncurrent assets, net29,878 35,915 
Total assets$4,717,132 $5,878,946 
Liabilities and stockholders' equity
Current liabilities:
Accounts payable and accrued liabilities$195,566 $185,115 
Accrued capital expenditures93,390 95,593 
Undistributed revenue and royalties142,799 187,563 
Operating lease liabilities28,087 73,143 
Other current liabilities81,637 59,725 
Total current liabilities541,479 601,139 
Long-term debt, net2,282,320 2,454,242 
Derivatives25,837 5,814 
Asset retirement obligations76,040 82,941 
Operating lease liabilities29,218 26,733 
Other noncurrent liabilities6,020 7,506 
Total liabilities2,960,914 3,178,375 
Commitments and contingencies
Stockholders' equity:
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued and outstanding as of September 30, 2025 and December 31, 2024
— — 
Common stock, $0.01 par value, 80,000,000 shares authorized, and 38,690,302 and 38,144,248 issued and outstanding as of September 30, 2025 and December 31, 2024, respectively
387 381 
Additional paid-in capital3,833,813 3,823,241 
Accumulated deficit(2,077,982)(1,123,051)
Total stockholders' equity1,756,218 2,700,571 
Total liabilities and stockholders' equity$4,717,132 $5,878,946 

The accompanying notes are an integral part of these unaudited consolidated financial statements.
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Vital Energy, Inc.
Consolidated statements of operations
(in thousands, except per share data)
(Unaudited)
Three months ended September 30, Nine months ended September 30,
2025202420252024
Revenues:
Oil sales$367,511 $416,668 $1,155,448 $1,274,119 
NGL sales42,929 41,807 155,714 128,752 
Natural gas sales9,206 (9,724)47,175 3,150 
Sales of purchased oil— 8,986 — 8,986 
Other operating revenues1,180 1,497 4,296 2,937 
Total revenues420,826 459,234 1,362,633 1,417,944 
Costs and expenses:
Lease operating expenses114,259 107,686 325,494 327,156 
Production and ad valorem taxes20,525 27,244 80,106 84,937 
Oil transportation and marketing expenses10,527 12,445 31,296 34,477 
Gas gathering, processing and transportation expenses6,774 4,602 18,910 12,066 
Costs of purchased oil— 9,331 — 9,331 
General and administrative25,046 22,005 71,517 74,934 
Organizational restructuring expenses— — 4,627 — 
Depletion, depreciation and amortization180,516 187,063 556,840 527,468 
Impairment expense419,955 — 1,005,242 — 
Other operating expenses, net6,280 1,754 10,456 5,365 
Total costs and expenses783,882 372,130 2,104,488 1,075,734 
Gain (loss) on disposal of assets, net685 839 2,050 1,005 
Operating income (loss)(362,371)87,943 (739,805)343,215 
Non-operating income (expense):
Gain (loss) on derivatives, net56,069 226,553 169,233 82,064 
Interest expense(49,994)(40,119)(150,228)(124,230)
Loss on extinguishment of debt, net— — — (66,115)
Other income (expense), net999 1,247 2,215 5,921 
Total non-operating income (expense), net7,074 187,681 21,220 (102,360)
Income (loss) before income taxes(355,297)275,624 (718,585)240,855 
Income tax benefit (expense)1,775 (60,324)(236,346)(54,984)
Net income (loss)(353,522)215,300 (954,931)185,871 
Preferred stock dividends— — — (652)
Net income (loss) available to common stockholders$(353,522)$215,300 $(954,931)$185,219 
Net income (loss) per common share:
Basic$(9.35)$5.75 $(25.32)$5.08 
Diluted$(9.35)$5.73 $(25.32)$4.97 
Weighted-average common shares outstanding:
Basic37,801 37,459 37,714 36,472 
Diluted37,801 37,580 37,714 37,370 

The accompanying notes are an integral part of these unaudited consolidated financial statements.
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Vital Energy, Inc.
Consolidated statements of stockholders' equity
(in thousands)
(Unaudited)
Preferred StockCommon stockAdditional
paid-in capital		Treasury stock
(at cost)		Accumulated deficit
SharesAmountSharesAmountSharesAmountTotal
Balance, December 31, 2024— $— 38,144 $381 $3,823,241 — $— $(1,123,051)$2,700,571 
Restricted stock awards— — 651 7 (7)— — — — 
Restricted stock forfeitures— — (7)— — — — — — 
Stock exchanged for tax withholding— — (126)(1)(3,922)126 3,923 — — 
Retirement of treasury stock— — — — — (126)(3,923)— (3,923)
Share-settled equity-based compensation— — — — 4,694 — — — 4,694 
Performance share conversion— — 40 — — — — — — 
Net income (loss)— — — — — — — (18,837)(18,837)
Balance, March 31, 2025— — 38,702 387 3,824,006 — — (1,141,888)2,682,505 
Restricted stock awards— — 24 — — — — — — 
Restricted stock forfeitures— — (106)(1)1 — — — — 
Stock exchanged for tax withholding——(2)—(33)233—— 
Retirement of treasury stock— — — — — (2)(33)— (33)
Share-settled equity-based compensation— — — — 4,167 — — — 4,167 
Other— — 70 1 1,510 — — — 1,511 
Net income (loss)— — — — — — (582,572)(582,572)
Balance, June 30, 2025— — 38,688 387 3,829,651 — — (1,724,460)2,105,578 
Restricted stock awards— — 17 — — — — — — 
Restricted stock forfeitures— — (15)— — — — — — 
Stock exchanged for tax withholding— — — — (10)— 10 — — 
Retirement of treasury stock— — — — — — (10)— (10)
Share-settled equity-based compensation— — — — 4,172 — — — 4,172 
Net income (loss)— — — — — — — (353,522)(353,522)
Balance, September 30, 2025— $— 38,690 $387 $3,833,813 — $— $(2,077,982)$1,756,218 

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Preferred StockCommon stockAdditional
paid-in capital		Treasury stock
(at cost)		Accumulated deficit
SharesAmountSharesAmountSharesAmountTotal
Balance, December 31, 2023595 $6 35,414 $354 $3,733,775 — $— $(948,878)$2,785,257 
Restricted stock awards— — 445 5 (4)— — — 1 
Restricted stock forfeitures— — (5)— — — — — — 
Stock exchanged for tax withholding— — (72)(1)(3,410)72 3,411 — — 
Retirement of treasury stock— — — — — (72)(3,411)— (3,411)
Share-settled equity-based compensation— — — — 4,348 — — — 4,348 
Equity issued for acquisition of oil and natural gas properties980 10 879 9 78,721 — — — 78,740 
Net income (loss)— — — — — — — (66,131)(66,131)
Balance, March 31, 20241,575 16 36,661 367 3,813,430 — — (1,015,009)2,798,804 
Restricted stock awards— — 13 — — — — — — 
Restricted stock forfeitures— — (8)— — — — — — 
Stock exchanged for tax withholding— — — — (9)— 9 — — 
Retirement of treasury stock— — — — — — (9)— (9)
Share-settled equity-based compensation— — — — 4,865 — — — 4,865 
Equity issued for acquisition of oil and natural gas properties— — (76)(1)(3,811)— — — (3,812)
Preferred stock conversion(1,575)(16)1,575 16 — — — — — 
Preferred stock dividend paid— — — — — — — (652)(652)
Net income (loss)— — — — — — — 36,702 36,702 
Balance, June 30, 2024— — 38,165 382 3,814,475 — — (978,959)2,835,898 
Restricted stock awards— — 12 — — — — — — 
Restricted stock forfeitures— — (5)— — — — — — 
Stock exchanged for tax withholding— — (3)— (113)3 113 — — 
Retirement of treasury stock— — — — — (3)(113)— (113)
Share-settled equity-based compensation— — — — 4,756 — — — 4,756 
Net income (loss)— — — — — — — 215,300 215,300 
Balance, September 30, 2024— $— 38,169 $382 $3,819,118 — $— $(763,659)$3,055,841 

The accompanying notes are an integral part of these unaudited consolidated financial statements.
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Vital Energy, Inc.
Consolidated statements of cash flows
(in thousands)
(Unaudited)
Nine months ended September 30,
20252024
Cash flows from operating activities:
Net income (loss)$(954,931)$185,871 
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Share-settled equity-based compensation, net9,997 11,248 
Depletion, depreciation and amortization556,840 527,468 
Impairment expense1,005,242 — 
Mark-to-market on derivatives:
(Gain) loss on derivatives, net(169,233)(82,064)
Settlements received (paid) for matured derivatives, net155,002 10,751 
Loss on extinguishment of debt, net— 66,115 
Deferred income tax (benefit) expense233,714 52,278 
Other, net29,785 19,608 
Changes in operating assets and liabilities:
Accounts receivable, net71,479 13,815 
Other current assets(8,585)(7,667)
Other noncurrent assets, net(5,813)(836)
Accounts payable and accrued liabilities10,451 (21,281)
Undistributed revenue and royalties(44,764)(19,593)
Other current liabilities22,957 (1,432)
Other noncurrent liabilities(22,263)(11,125)
Net cash provided by (used in) operating activities889,878 743,156 
Cash flows from investing activities:
Acquisitions of oil and natural gas properties, net(1,636)(831,225)
Capital expenditures:
Oil and natural gas properties(756,640)(633,279)
Midstream and other fixed assets(7,432)(16,630)
Proceeds from dispositions of capital assets, net of selling costs33,059 2,741 
Other, net766 (1,776)
Net cash provided by (used in) investing activities(731,883)(1,480,169)
Cash flows from financing activities:
Borrowings on Senior Secured Credit Facility450,000 1,440,000 
Payments on Senior Secured Credit Facility(625,000)(715,000)
Issuance of senior unsecured notes— 1,001,500 
Extinguishment of debt— (952,214)
Stock exchanged for tax withholding(3,966)(3,533)
Payments for debt issuance costs— (21,738)
Other, net(4,511)(3,871)
Net cash provided by (used in) financing activities(183,477)745,144 
Net increase (decrease) in cash and cash equivalents(25,482)8,131 
Cash and cash equivalents, beginning of period40,179 14,061 
Cash and cash equivalents, end of period$14,697 $22,192 
 The accompanying notes are an integral part of these unaudited consolidated financial statements.
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Vital Energy, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
Note 1—Organization and basis of presentation
Organization
Vital Energy, Inc. ("Vital Energy," "Vital" or the "Company"), together with its wholly-owned subsidiary, Vital Midstream Services, LLC ("VMS"), is an independent energy company focused on the acquisition, exploration and development of oil and natural gas properties in the Permian Basin of West Texas. In these notes, the "Company" refers to Vital Energy and VMS collectively, unless the context indicates otherwise. All amounts, dollars and percentages presented in these unaudited consolidated financial statements and the related notes are rounded and, therefore, approximate.
Explanatory Note
On August 24, 2025, the Company entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Crescent Energy Company, a Delaware corporation ("Crescent"), Venus Merger Sub I Inc., a Delaware corporation and a wholly owned subsidiary of Crescent (“Merger Sub Inc.”), and Venus Merger Sub II LLC, a Delaware limited liability company and a wholly owned subsidiary of Crescent (“Merger Sub LLC”). Pursuant to the terms of the Merger Agreement, Crescent will acquire the Company in an all-equity transaction through: (i) the merger of Merger Sub Inc. (the “First Company Merger”) with and into the Company, with the Company continuing as the surviving entity (the “Surviving Corporation”) and (ii) immediately following the First Company Merger, the merger of the Surviving Corporation (the “Second Company Merger” and, together with the First Company Merger, the “Mergers”) with and into Merger Sub LLC, with Merger Sub LLC continuing as the surviving entity (the “Surviving Company”), in each case, on the terms and subject to the conditions set forth in the Merger Agreement.
On the terms and subject to the conditions set forth in the Merger Agreement:
•at the effective time of the First Company Merger (the “Effective Time”), (i) each share of capital stock of Merger Sub Inc. issued and outstanding immediately prior to the Effective Time will be converted into and will represent one fully paid and nonassessable share of common stock, par value $0.01 per share, of the Surviving Corporation and (ii) each share of common stock, par value $0.01 per share, of the Company (“Common Stock”), issued and outstanding immediately prior to the Effective Time (excluding each share of Common Stock held by the Company as treasury shares or by Crescent, Merger Sub Inc. or Merger Sub LLC, or by any wholly owned subsidiary of the Company, Merger Sub Inc. or Merger Sub LLC immediately prior to the Effective Time ("Excluded Shares")) will be converted into the right to receive from Crescent 1.9062 fully paid and nonassessable shares of Class A common stock, par value $0.0001 per share, of Crescent (the “Crescent Common Stock” and such right to receive Crescent Common Stock, the "Merger Consideration"), with cash to be paid in lieu of fractional shares, if any, and (iii) each Excluded Share will automatically be canceled and will cease to exist and no consideration will be delivered in exchange for such share; and
•at the effective time of the Second Company Merger (the “Second Company Merger Effective Time”), (i) each share of common stock of the Surviving Corporation issued and outstanding immediately prior to the Second Company Merger Effective Time will automatically be cancelled and cease to exist, and no consideration will be delivered in exchange therefor, and (ii) the limited liability company interests of Merger Sub LLC issued and outstanding as of immediately prior to the Second Company Merger Effective Time will remain outstanding and will not be affected by virtue of the Second Company Merger, and no consideration will be paid in respect thereof, and Crescent will continue as the sole member of the Surviving Company.
As a result of the Mergers and as of the closing of the Mergers (the “Closing”), the Company's stockholders as of immediately prior to the Effective Time will own approximately 23% of the outstanding shares of Crescent Common Stock, and Crescent's stockholders as of immediately prior to the Effective Time will own approximately 77% of the outstanding shares of Crescent Common Stock. Pursuant to the Merger Agreement, prior to the Effective Time, Crescent will (i) cause the number of directors constituting the board of directors of Crescent (the “Crescent Board”) to increase to 12, to become effective immediately prior to, but conditioned on, the Effective Time and (ii) appoint two directors designated by the Company and reasonably acceptable to Crescent to the Crescent Board as of the Effective Time (such directors, the “Company Designated Directors”).
Our board of directors (the “Board”) and the Crescent Board have each unanimously approved and declared advisable the Merger Agreement and transactions contemplated thereby. The completion of the Mergers is generally subject to certain
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Vital Energy, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
customary mutual conditions, including (i) the receipt of the required approval from the Company’s stockholders, (ii) the receipt of the required approval from Crescent’s stockholders, (iii) the termination or expiration of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, (iv) the absence of any governmental order or law that makes consummation of the Mergers illegal or otherwise prohibited, (v) Crescent’s registration statement on Form S-4 having been declared effective by the SEC under the Securities Act and no stop order having been issued, initiated or, to the knowledge of the Company or Crescent, threatened by the SEC, and (vi) the shares of Crescent Common Stock issuable in connection with the Mergers having been authorized for listing on the NYSE, subject to official notice of issuance. The obligation of each party to consummate the Mergers is further generally conditioned upon certain of the parties’ representations and warranties being true and correct (subject to certain materiality exceptions), the absence of a material adverse effect on each party, the parties having performed in all material respects their respective obligations under the Merger Agreement, and the receipt by each party of a compliance certificate. Until the approval by shareholders and the subsequent closing (as described above), the Company must continue to operate as a stand-alone entity.
Basis of presentation
The unaudited consolidated financial statements were derived from the historical accounting records of the Company and reflect the historical financial position, results of operations and cash flows for the periods described herein. The unaudited consolidated financial statements have been prepared in accordance with GAAP. All material intercompany transactions and account balances have been eliminated in the consolidation of accounts.
The unaudited consolidated financial statements have not been audited by the Company's independent registered public accounting firm, except that the consolidated balance sheet as of December 31, 2024 is derived from the Company's audited consolidated financial statements. In the opinion of management, the unaudited consolidated financial statements reflect all necessary adjustments to present fairly the Company's interim financial position, results of operations and cash flows. All adjustments are of a recurring nature unless otherwise disclosed herein.
Certain disclosures have been condensed or omitted from the unaudited consolidated financial statements. Accordingly, the unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in the 2024 Annual Report.
Significant accounting policies
There have been no material changes in the Company's significant accounting policies during the nine months ended September 30, 2025. See Note 2 in the 2024 Annual Report for further discussion of significant accounting policies.
Use of estimates
The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ.
See Note 2 in the 2024 Annual Report for further information regarding the use of estimates and assumptions.
Note 2—New accounting standards
The Company considered the applicability and impact of all Accounting Standards Updates ("ASU") issued by the Financial Accounting Standards Board ("FASB") to the Accounting Standards Codification. There were no new ASUs adopted during the nine months ended September 30, 2025. See below for discussion of ASUs not yet adopted.
ASU not yet adopted
In November 2024, the FASB issued ASU 2024-03, Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses, which requires additional disclosure about specific types of expenses included in the expense captions presented on the income statement. The amendments in this accounting standard are effective, on a prospective basis, for fiscal years beginning after December 15, 2026, and interim periods beginning after December 15, 2027. Early adoption is permitted. Adoption of this ASU is expected
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Vital Energy, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
to result in additional disclosure, but will not impact the Company's consolidated financial position, results of operations or cash flows.
In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures, which requires more detailed tax disclosures, including disaggregated information about an entity's effective tax rate reconciliation as well as expanded information on income taxes paid by jurisdiction. The amendments in this accounting standard are effective for fiscal years beginning after December 15, 2024, on a prospective basis. Early adoption is permitted. Adoption of this ASU is expected to result in additional disclosure, but will not impact the Company’s consolidated financial position, results of operations or cash flows.
Note 3—Acquisitions
Point Acquisition
On September 20, 2024 (the "Point Closing Date"), the Company, together with Northern Oil and Gas, Inc. ("NOG"), purchased certain oil and natural gas properties located in the Delaware Basin from Point Energy Partners Petroleum, LLC, Point Energy Partners Operating, LLC, Point Energy Partners Water, LLC and Point Energy Partners Royalty, LLC (collectively, “Point”) for an aggregate purchase price of $1.0 billion in cash, including closing adjustments (the "Point Acquisition"). The Company purchased 80% of the acquired assets, consisting of approximately 16,300 net acres in Ward and Winkler Counties, and will operate the assets, and NOG purchased the remaining 20% of the assets. The Company's portion of the aggregate preliminary purchase price was $827.0 million, which consisted of (i) $805.1 million in cash and (ii) $21.9 million of estimated transaction-related expenses. See Note 4 in the 2024 Annual Report for additional discussion of the Point Acquisition.
PEP Acquisition
On February 2, 2024, the Company purchased additional working interests in producing properties associated with a previous acquisition. The aggregate purchase price, inclusive of final adjustments, of $77.6 million consisted of (i) 878,690 shares of Common Stock based upon the share price as of the closing date, totaling $37.1 million, (ii) 980,272 shares of the Company's 2.0% Cumulative Mandatorily Convertible Series A Preferred Stock, par value $0.01 per share ("Preferred Stock") based upon the share price as of the closing date, totaling $41.3 million, (iii) the fair value of preferred stock dividends totaling $0.3 million, (iv) $1.8 million of cash consideration received for closing adjustments and (v) $0.7 million in transaction-related expenses. The 980,272 shares of Preferred Stock were subsequently converted to an equal number of shares of Common Stock on May 23, 2024. See Note 4 in the 2024 Annual Report for additional discussion of the PEP Acquisition.
Note 4—Property and equipment
Full cost ceiling impairment
As discussed in Note 2 in the 2024 Annual Report, the Company uses the full cost method of accounting for its oil and natural gas properties. This accounting method requires a quarterly full cost ceiling test. The full cost ceiling is based principally on the estimated future net revenues from proved oil, NGL and natural gas reserves, which exclude the effect of the Company's commodity derivative transactions, discounted at 10%. The SEC guidelines require companies to use the unweighted arithmetic average first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period before differentials ("Benchmark Prices"). The Benchmark Prices are then adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead ("Realized Prices") without giving effect to the Company's commodity derivative transactions. The Realized Prices are utilized to calculate the estimated future net revenues in the full cost ceiling calculation. Additional significant inputs included in the calculation of discounted cash flows used in the impairment analysis include the Company's estimate of operating and development costs, anticipated production of proved reserves and other relevant data. In the event the unamortized cost of evaluated oil and natural gas properties being depleted exceeds the full cost ceiling, as defined by the SEC, the excess is expensed in the period such excess occurs. Once incurred, a write-down of oil and natural gas properties is not reversible.

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Vital Energy, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
The unamortized cost of evaluated oil and natural gas properties being depleted exceeded the full cost ceiling as of September, 30, 2025, June 30, 2025 and March 31, 2025. The following table presents full cost ceiling impairment expense, which is included in "Impairment expense" on the unaudited consolidated statements of operations, for the periods presented:
Three months ended September 30,Nine months ended September 30,
(in thousands)2025202420252024
Full cost ceiling impairment expense$419,955 $— $1,005,242 $— 
If prices remain at or below the current levels, subject to numerous factors and inherent limitations and all other factors remain constant, we could incur additional non-cash full cost ceiling impairments in future quarters, which will have an adverse effect on our statement of operations.
The following table presents the Benchmark Prices and the Realized Prices utilized in the full cost ceiling calculation as of the dates presented:
September 30, 2025June 30, 2025March 31, 2025December 31, 2024September 30, 2024
Benchmark Prices:
Oil ($/Bbl)$67.45 $70.48 $74.52 $75.48 $78.64 
NGL ($/Bbl)(1)
$67.45 $70.48 $74.52 $75.48 $78.64 
Natural gas ($/MMBtu)$3.10 $2.86 $2.44 $2.13 $2.21 
Realized Prices:
Oil ($/Bbl)$68.35 $71.47 $75.55 $76.76 $79.92 
NGL ($/Bbl)$16.16 $15.65 $13.87 $13.66 $14.06 
Natural gas ($/Mcf)$1.11 $0.98 $1.04 $0.85 $0.81 
_____________________________________________________________________________
(1)    The Company utilizes WTI NYMEX in the calculation of its NGL Benchmark Prices.
Divestiture
During 2025, the Company sold non-core oil and natural gas properties for net proceeds of $30.5 million. Pursuant to the rules governing full cost accounting, the net proceeds and removal of $8.4 million in asset retirement obligations were recorded as adjustments to oil and natural gas properties.
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Vital Energy, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
Note 5—Debt
Long-term debt, net
The following table presents the Company's long-term debt and unamortized debt issuance costs, discounts and premiums included in "Long-term debt, net" on the consolidated balance sheets as of the dates presented:
(in thousands)September 30, 2025December 31, 2024
7.750% senior unsecured notes due 2029 (July 2029 Notes)
$298,214 $298,214 
9.750% senior unsecured notes due 2030 (September 2030 Notes)
302,364 302,364 
7.875% senior unsecured notes due 2032 (March 2032 Notes)
1,000,000 1,000,000 
Senior Secured Credit Facility705,000 880,000 
Total long-term debt2,305,578 2,480,578 
Unamortized debt issuance costs(1)
(21,762)(24,579)
Unamortized discounts(2,730)(3,132)
Unamortized premiums1,234 1,375 
Total long-term debt, net$2,282,320 $2,454,242 
______________________________________________________________________________
(1)Unamortized debt issuance costs related to the Senior Secured Credit Facility of $9.1 million and $12.5 million as of September 30, 2025 and December 31, 2024, respectively, are included in "Other noncurrent assets, net" on the consolidated balance sheets.
Senior Secured Credit Facility
As of September 30, 2025, the Senior Secured Credit Facility, which matures on September 13, 2027, had a maximum credit amount of $3.0 billion, a borrowing base and an aggregate elected commitment of $1.4 billion, and an outstanding balance of $705.0 million subject to a weighted-average interest rate of 7.008%. The Senior Secured Credit Facility contains both financial and non-financial covenants, all of which the Company was in compliance with for all periods presented. Additionally, the Senior Secured Credit Facility provides for the issuance of letters of credit, limited to the lesser of total capacity or $80.0 million. As of September 30, 2025 and December 31, 2024, the Company had no letters of credit outstanding under the Senior Secured Credit Facility. For additional information on the Senior Secured Credit Facility, see Note 7 in the 2024 Annual Report.
Subsequent to September 30, 2025, the Company borrowed $95.0 million and repaid $75.0 million on the Senior Secured Credit Facility. As a result, the outstanding balance under the Senior Secured Credit Facility was $725.0 million as of October 29, 2025.
As a result of and in light of the pending merger with Crescent, the Company requested that Wells Fargo Bank, N.A., as administrative agent of the Senior Secured Credit Facility, and the banks signatory thereto, enter into a letter agreement to consent to postponing the fall 2025 borrowing base redetermination until December 19, 2025 from the currently required date of on or around November 1, 2025. The executed letter agreement was received by the Company before November 1, 2025.
Senior unsecured notes
On March 28, 2024, the Company completed an offering of $800.0 million in aggregate principal amount of 7.875% senior unsecured notes due 2032 (the "Initial March 2032 Notes") for net proceeds of $784.8 million. The net proceeds from this offering and the Tack-On March 2032 Notes (defined below) were used to (i) extinguish in full the Company's 10.125% senior unsecured notes due 2028 (the "January 2028 Notes"), (ii) reduce the outstanding principal amount of the 9.750% senior unsecured notes due 2030 (the "September 2030 Notes") and (iii) repay a portion of the outstanding borrowings on the Senior Secured Credit Facility. On March 29, 2024, the Company settled a cash tender offer on the January 2028 Notes for an aggregate principal amount outstanding of $431.2 million.
On April 3, 2024, the Company completed an offering of an additional $200.0 million in aggregate principal amount of 7.875% senior unsecured notes due 2032 (the "Tack-On March 2032 Notes," and, together with the Initial March 2032 Notes, the "March 2032 Notes"), at 100.750% of par, under the same indenture dated as of March 28, 2024 for net proceeds of
10
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Vital Energy, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
approximately $198.7 million. On April 3, 2024, the Company settled a cash tender offer on the September 2030 Notes of $197.6 million and on April 29, 2024, the Company redeemed the remaining principal amount outstanding on the January 2028 Notes of $269.2 million at a redemption price of 105.063%.
The following table presents the components of the Company's loss on extinguishment of debt, net during the period presented:
(in thousands)Nine months ended
September 30, 2024
Principal amount tendered or redeemed$897,945 
Extinguishment of debt(1)
(952,214)
Early tender or redemption premiums(54,269)
Write-off of debt issuance costs(13,121)
Write-off of issuance discount(2,311)
Write-off of issuance premium3,586 
Loss on extinguishment of debt, net(2)
$(66,115)
______________________________________________________________________________
(1)Amounts are included in "Extinguishment of debt" in cash flows from financing activities on the consolidated statements of cash flows.
(2)Amounts are included in "Loss on extinguishment of debt, net" on the consolidated statements of operations.

No gain or loss on extinguishment of debt was recorded during the three and nine months ended September 30, 2025 or the three months ended September 30, 2024.
Note 6—Equity Incentive Plan
The Vital Energy, Inc. Omnibus Equity Incentive Plan (the "Equity Incentive Plan") provides for the granting of incentive awards in the form of restricted stock awards, stock option awards, performance share unit awards, restricted stock unit awards, stock appreciation rights, stock bonus awards and other awards. The Equity Incentive Plan allows for the issuance of up to 3,332,500 shares.
See Note 9 in the 2024 Annual Report for additional discussion of the Company's equity-based compensation awards.
The following table presents activity for equity-based compensation awards for the nine months ended September 30, 2025:
Equity AwardsLiability Awards
(in thousands)Restricted stock awards
Share-settled performance share unit awards(1)
Cash-settled performance share unit awards(2)
Outstanding as of December 31, 2024
665 48 215 
Granted692 — 192 
Forfeited(128)— (4)
Vested(345)(48)— 
Outstanding as of September 30, 2025
884 — 403 
_____________________________________________________________________________
(1)The share-settled performance share unit awards granted on February 22, 2022 had a performance period of January 1, 2022 to December 31, 2024 and, as their market and performance criteria were satisfied, resulted in an 82% payout. As such, the granted awards vested and were converted into 39,691 shares of Common Stock during the first quarter of 2025 based on this 82% payout.
(2)On February 20, 2025, the Company granted cash-settled performance share unit awards with a performance period of January 1, 2025 through December 31, 2027. The market criteria consists of: (i) relative total shareholder return comparing the Company's shareholder return to the shareholder return of the exploration and production companies listed in the Russell 2000 Index and (ii) absolute shareholder return. The performance criteria consists of: (i) earnings before interest, taxes, depreciation, amortization and exploration expense and three-year total debt reduction and
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Vital Energy, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
(ii) an inventory quality component. Any units earned are expected to be paid in cash during the first quarter following the completion of the requisite service period, based on the achievement of market and performance criteria, and the payout can range from 0% to 225%.
As of September 30, 2025, total unrecognized cost related to equity-based compensation awards was $25.7 million, of which $3.5 million was attributable to liability awards which will be settled in cash rather than shares. Such cost will be recognized on a straight-line basis over an expected weighted-average period of 1.94 years.
Equity-based compensation
The following table reflects equity-based compensation expense for the periods presented:
Three months ended September 30,Nine months ended September 30,
(in thousands)2025202420252024
Equity awards:
Restricted stock awards$4,172 $4,421 $12,752 $12,615 
Share-settled performance share unit awards— 335 281 1,354 
Total share-settled equity-based compensation, gross4,172 4,756 13,033 13,969 
Less: amounts capitalized(1,012)(943)(3,036)(2,721)
Total share-settled equity-based compensation, net3,160 3,813 9,997 11,248 
Liability awards:
Cash-settled performance unit awards328 (411)(42)1,816 
Total cash-settled equity-based compensation, gross328 (411)(42)1,816 
Less: amounts capitalized — — (2)(14)
Total cash-settled equity-based compensation, net328 (411)(44)1,802 
Total equity-based compensation, net$3,488 $3,402 $9,953 $13,050 
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Vital Energy, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
Note 7—Net income (loss) per common share
Basic net income (loss) per common share is computed by first subtracting preferred stock dividends, if any, from net income (loss) to arrive at net income (loss) available to common stockholders, and then dividing net income (loss) available to common stockholders by the basic weighted-average common shares outstanding for the period. Diluted net income (loss) per common share is computed by dividing net income (loss) by the diluted weighted-average common shares outstanding for the period, which reflects the potential dilution of non-vested equity-based compensation awards and outstanding preferred stock. In periods where the Company has a net loss, the non-vested equity-based compensation awards and outstanding preferred stock are excluded from the calculation of diluted net loss per common share as their effect would be anti-dilutive. See Notes 8 and 9 in the 2024 Annual Report for additional discussion of the Company's preferred stock and equity-based compensation awards, respectively.
The following table reflects the calculations of basic and diluted (i) weighted-average common shares outstanding and (ii) net income (loss) per common share for the periods presented:
Three months ended September 30,Nine months ended September 30,
(in thousands, except for per share data)2025202420252024
Net income (loss)$(353,522)$215,300 $(954,931)$185,871 
Less: preferred stock dividends— — — 652 
Net income (loss) available to common stockholders$(353,522)$215,300 $(954,931)$185,219 
Weighted-average common shares outstanding:
Basic37,801 37,459 37,714 36,472 
Dilutive non-vested restricted stock awards— 102 — 108 
Dilutive non-vested share-settled performance share unit awards— 19 — 13 
Dilutive preferred stock— — — 777 
Diluted37,801 37,580 37,714 37,370 
Net income (loss) per common share:
Basic$(9.35)$5.75 $(25.32)$5.08 
Diluted$(9.35)$5.73 $(25.32)$4.97 
Anti-dilutive weighted-average common shares outstanding(1):
Non-vested restricted stock awards714396745104
Non-vested share-settled performance share unit awards——7—
_____________________________________________________________________________
(1)Shares excluded from the diluted net income (loss) per common share calculation because their effect would be anti-dilutive.
Note 8—Derivatives
The Company has two types of derivative instruments as of September 30, 2025: (i) commodity derivatives and (ii) a contingent consideration derivative. See Note 9 for discussion of fair value measurement of derivatives on a recurring basis. The Company's derivatives were not designated as hedges for accounting purposes, and the Company does not enter into such instruments for speculative trading purposes. Accordingly, the changes in derivative fair values are recognized in "Gain (loss) on derivatives, net" under "Non-operating income (expense)" on the consolidated statements of operations.

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Vital Energy, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
The following table summarizes components of the Company's gain on derivatives, net by type of derivative instrument for the periods presented:
Three months ended September 30,Nine months ended September 30,
(in thousands)2025202420252024
Commodity$62,778 $237,103 $167,027 $90,693 
Contingent consideration(6,709)(10,550)2,206 (8,629)
Gain (loss) on derivatives, net$56,069 $226,553 $169,233 $82,064 
Commodity
Due to the inherent volatility in oil, NGL and natural gas prices and the sometimes wide pricing differentials between where the Company produces and where the Company sells such commodities, the Company engages in commodity derivative transactions, such as puts, swaps, collars and basis swaps, to hedge price risk associated with a portion of the Company's anticipated sales volumes. By removing a portion of the price volatility associated with future sales volumes, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flows from operations. During the nine months ended September 30, 2025, the Company’s derivatives were settled based on reported prices on commodity exchanges, with (i) oil derivatives settled based on WTI NYMEX pricing, (ii) NGL derivatives settled based on Mont Belvieu OPIS pricing and (iii) natural gas derivatives settled based on Henry Hub NYMEX and Waha Inside FERC pricing.
The following table summarizes open commodity derivative positions as of September 30, 2025, for commodity derivatives that were entered into through September 30, 2025, for the settlement periods presented:
Remaining Year 2025Year 2026Year 2027
Oil:
WTI NYMEX - Swaps:
Volume (Bbl)6,053,600 13,306,500 3,285,000 
Weighted-average price ($/Bbl)$67.75 $64.02 $61.07 
WTI NYMEX - Collars:
Volume (Bbl)— 1,086,000 — 
Weighted-average floor price ($/Bbl)$— $60.00 $— 
Weighted-average ceiling price ($/Bbl)$— $71.02 $— 
NGL:
Non-TET Propane - Swaps:
Volume (Bbl)874,000 — — 
Weighted-average price ($/Bbl)$34.16 $— $— 
Non-TET Ethane - Swaps:
Volume (Bbl)1,104,000 — — 
Weighted-average price ($/Bbl)$11.04 $— $— 
Natural gas:
Waha Inside FERC - Swaps:
Volume (MMBtu)15,034,000 55,480,000 43,800,000 
Weighted-average price ($/MMBtu)$2.32 $2.41 $2.70 
Waha Inside FERC to Henry Hub NYMEX - Basis Swaps:
Volume (MMBtu)— — 14,600,000 
Weighted-average differential ($/MMBtu)$— $— $(0.97)
Contingent consideration
On May 7, 2021, the Company entered into a purchase and sale agreement (the "Sixth Street PSA"), to sell 37.5% of the Company's working interest in certain producing wellbores and the related properties primarily located within Glasscock and Reagan Counties, Texas. The Sixth Street PSA provides for potential contingent payments to be paid to the Company if certain
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Vital Energy, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
cash flow targets are met related to divested oil and natural gas property operations (the "Sixth Street Contingent Consideration"). The Sixth Street Contingent Consideration provides the Company with the right to receive up to a maximum of $93.7 million in additional cash consideration, comprised of potential quarterly payments through June 2027 totaling up to $38.7 million, of which $20.0 million is still remaining, and a potential balloon payment of $55.0 million in June 2027. The estimated fair value of the Sixth Street Contingent Consideration was $18.5 million as of September 30, 2025 and $16.3 million as of December 31, 2024.
Note 9—Fair value measurements
See the beginning of Note 12 in the 2024 Annual Report for information about the fair value hierarchy levels.
Fair value measurement on a recurring basis
See Note 8 for further discussion of the Company's derivatives.
Balance sheet presentation
The following tables present the Company's derivatives by (i) balance sheet classification, (ii) derivative type and (iii) fair value hierarchy level, and provide a total, on a gross basis and a net basis reflected in "Derivatives" on the consolidated balance sheets as of the dates presented:
September 30, 2025
(in thousands)Level 1Level 2Level 3Total gross fair valueAmounts offsetNet fair value presented on the consolidated balance sheets
Assets:
Current:
Commodity$— $158,376 $— $158,376 $(9,095)$149,281 
Contingent consideration— — 51 51 — 51 
Noncurrent:
Commodity— (1,834)— (1,834)4,324 2,490 
Contingent consideration— — 18,470 18,470 — 18,470 
Liabilities:
Current:
Commodity— (9,095)— (9,095)9,095 — 
Noncurrent:
Commodity— (21,513)— (21,513)(4,324)(25,837)
Net derivative asset (liability) positions$— $125,934 $18,521 $144,455 $— $144,455 
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Vital Energy, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
December 31, 2024
(in thousands)Level 1Level 2Level 3Total gross fair valueAmounts offsetNet fair value presented on the consolidated balance sheets
Assets:
Current:
Commodity$— $98,825 $— $98,825 $2,638 $101,463 
Contingent consideration— — 11 11 — 11 
Noncurrent:
Commodity— 28,126 — 28,126 (9,866)18,260 
Contingent consideration— — 16,304 16,304 — 16,304 
Liabilities:
Current:
Commodity— 2,638 — 2,638 (2,638)— 
Noncurrent:
Commodity— (15,680)— (15,680)9,866 (5,814)
Net derivative asset (liability) positions$— $113,909 $16,315 $130,224 $— $130,224 
See Note 12 in the 2024 Annual Report for discussion of the significant inputs used in the fair value mark-to-market analysis of commodity and contingent consideration derivatives. The Company reviewed the third-party specialist's valuations of commodity and contingent consideration derivatives, including the related inputs, and analyzed changes in fair values between reporting dates.
The Sixth Street Contingent Consideration is categorized as Level 3 in the fair value hierarchy, as the Company provided cash flow projections to a third-party valuation specialist to determine the fair value. The Company reviewed the third-party specialist's valuation, including the related inputs, and analyzed changes in fair values between the divestiture closing date and the reporting dates. The fair value at the closing date of the Sixth Street Contingent Consideration was recorded as part of the basis in the oil and natural gas properties divested and as a contingent consideration asset. At each quarterly reporting period, the Company remeasures contingent consideration with the change in fair values recognized in "Gain (loss) on derivatives, net" under "Non-operating income (expense)" on the consolidated statement of operations. See Note 8 for additional discussion of the Sixth Street Contingent Consideration.
The following table summarizes the changes in contingent consideration derivatives classified as Level 3 measurements for the periods presented:
Three months ended September 30,Nine months ended September 30,
(in thousands)2025202420252024
Balance of Level 3 at beginning of period$25,230 $33,027 $16,315 $31,106 
Change in Sixth Street Contingent Consideration fair value(6,709)(10,550)2,206 (8,629)
Balance of Level 3 at end of period$18,521 $22,477 $18,521 $22,477 
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Vital Energy, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
Items not accounted for at fair value
The carrying amounts reported on the consolidated balance sheets for cash and cash equivalents, accounts receivable, accounts payable, accrued capital expenditures, undistributed revenue and royalties and other accrued assets and liabilities approximate their fair values.
The Company has not elected to account for its debt instruments at fair value. The following table presents the carrying amounts and fair values of the Company's debt as of the dates presented:
September 30, 2025December 31, 2024
(in thousands)
Carrying
amount(1)
Fair
value(2)
Carrying
amount(1)
Fair
value(2)
Debt$2,305,578 $2,284,715 $2,480,578 $2,455,032 
______________________________________________________________________________
(1)Amounts presented do not include issuance premiums or discounts.
(2)The fair values of the outstanding notes were determined using the Level 2 fair value hierarchy quoted market prices for each respective instrument as of September 30, 2025 and December 31, 2024. The fair values of the outstanding amounts under the Senior Secured Credit Facility approximate the carrying values based on short-term floating interest rates available to the Company as of September 30, 2025 and December 31, 2024.
Note 10—Commitments and contingencies
From time to time, the Company is subject to various legal proceedings arising in the ordinary course of business, including those that arise from interpretation of federal, state and local laws and regulations affecting the oil and natural gas industry, personal injury claims, title disputes, royalty disputes, contract claims, contamination claims relating to oil and natural gas exploration and development and environmental claims, including claims involving assets previously sold to third parties and no longer part of the Company's current operations. The Company may not have insurance coverage for some of these proceedings and failure to comply with applicable laws and regulations can result in substantial penalties. While many of these matters involve inherent uncertainty, as of the date hereof, the Company believes that any such legal proceedings, if ultimately decided adversely, will not have a material adverse effect on the Company's business, financial position, results of operations or liquidity.
The Company has committed to deliver, for sale or transportation, fixed volumes of product under certain contractual arrangements that specify the delivery of a fixed and determinable quantity. If not fulfilled, the Company is subject to firm transportation payments on excess pipeline capacity and other contractual penalties. These commitments are normal and customary for the Company's business. In certain instances, the Company has used spot market purchases to meet its commitments in certain locations or due to favorable pricing. As of September 30, 2025, future firm sale and transportation commitments of $69.8 million are expected to be satisfied and, as such, are not recorded as a liability on the balance sheet.
The Company has committed to purchase a fixed supply of electricity at specified prices through 2032. As of September 30, 2025, future minimum payments under the terms of these agreements are $217.0 million.
The Company has committed to take delivery of processed sand, which is utilized in the Company's completions activities, at specified prices through 2026. As of September 30, 2025, future minimum purchase commitments under the terms of these agreements are estimated to be $26.9 million.
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Vital Energy, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
Note 11—Supplemental cash flow and non-cash information
The following table presents supplemental cash flow and non-cash information for the periods presented:
Nine months ended September 30,
(in thousands)20252024
Supplemental cash flow information:
Cash paid for interest, net of $207 and $1,181 of capitalized interest, respectively
$124,138 $111,798 
Supplemental non-cash operating information:
Right-of-use assets obtained in exchange for operating lease liabilities(1)
$26,875 $47,693 
Supplemental non-cash investing information:
Change in accrued capital expenditures$(2,203)$17,040 
Equity issued for acquisition of oil and natural gas properties(2)
$— $74,928 
Liabilities assumed in acquisitions of oil and natural gas properties(2)
$— $27,861 
_____________________________________________________________________________
(1)See Note 5 in the 2024 Annual Report for additional discussion of the Company's leases.
(2)See Note 3 for additional discussion of the Company's acquisitions.
Note 12—Income taxes
The following table presents income tax benefit (expense) for the periods presented:
Three months ended September 30,Nine months ended September 30,
(in thousands)2025202420252024
Current$(800)$(469)$(2,632)$(2,706)
Deferred2,575 (59,855)(233,714)(52,278)
Income tax benefit (expense)$1,775 $(60,324)$(236,346)$(54,984)
On July 4, 2025, the One Big Beautiful Bill Act (the "OBBB Act") was signed into law. The OBBB Act is a significant piece of tax legislation that includes provisions which permanently restore an EBITDA-based section 163(j) calculation for tax years beginning after December 31, 2024; restore 100% bonus depreciation under section 168(k) for certain property acquired and placed in service after January 19, 2025; and allow for current expensing of R&D expenditures. ASC 740-10 requires the impact of changes to tax law to be recorded in the period of enactment, which is reflected in these financial statements.
The Company estimates its annual effective tax rate (“AETR”) in recording its quarterly income tax provision for the various jurisdictions in which it operates. The tax effects of statutory rate changes, significant unusual or infrequently occurring items, and certain changes in the assessment of the realizability of deferred tax assets are excluded from the determination of its estimated AETR and are recognized as discrete items in the quarter in which they occur. The Company's AETR as of September 30, 2025 was 0%, which reflects the impact of providing a valuation allowance on the 2025 activity of the Company's federal net deferred tax asset. The Company's effective tax rate for the three months ended September 30, 2025 was 0.5%. During the second quarter of 2025, the Company recorded a discrete charge of $237.9 million related to the valuation allowance recorded on the December 31, 2024 federal net deferred tax asset. As such, the Company's effective tax rate for the nine months ended September 30, 2025 is not meaningful. The effective tax rate for the three and nine months ended September 30, 2024 was 21.89% and 22.83%, respectively. Current income tax expense is primarily attributable to Texas Franchise tax.
Management is required to assess the realizability of deferred tax assets for each reporting period. This assessment involves evaluating all available evidence, both positive and negative, to determine whether it is more-likely-than-not that the deferred tax assets will be realized. One of the most significant pieces of objective evidence is the existence of a cumulative pre-tax income or loss over the past three years. A three-year cumulative loss significantly constrains a company's ability to rely on projected future taxable income as a source of support for the realizability of deferred tax assets.
As a result of full cost ceiling impairments recorded during 2025, and the expectation of potential additional impairments in future periods, the Company is in a three-year pre-tax loss position and anticipates continuing to be in a cumulative three-year pre-tax loss position at year end. This represents a significant negative indicator under applicable accounting guidance and therefore management can no longer determine that it is more-likely-than-not that the Company's deferred tax assets
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Vital Energy, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
will be realized. Accordingly, as of June 30, 2025, the Company recorded and continues to maintain a valuation allowance against its federal net deferred tax asset. As of September 30, 2025, the Company maintains a full valuation allowance against its Oklahoma deferred tax assets but has not recorded a valuation allowance on its $6.0 million Texas net deferred tax asset.
As of September 30, 2025, the Company had federal net operating loss carryforwards totaling $922.1 million, of which $477.7 million will begin to expire in 2035 and $444.4 million will not expire but may be limited in future periods, and Oklahoma net operating loss carryforwards that do not expire totaling $297.1 million.
If the Company were to experience an "ownership change," as determined under Section 382 of the Internal Revenue Code, the Company's ability to offset taxable income arising after the ownership change with net operating loss carryforwards, interest expense carryforwards and certain other tax attributes arising prior to the ownership change could be significantly limited. Based on information available as of September 30, 2025, no such ownership change has occurred; however, the pending merger with Crescent is expected to result in an ownership change, which may significantly limit the future utilization of the Company's net operating loss carryforwards, interest expense carryforwards and other tax attributes. Moreover, as discussed above, as of September 30, 2025 these deferred tax assets are fully offset with a valuation allowance.
Note 13—Related parties
Halliburton
The Chairman of the Company's board of directors is on the board of directors of Halliburton Company ("Halliburton"). The Company had a lease agreement with Halliburton, which extended through 2025, to provide an electric fracture stimulation crew and the related services, which was terminated in third-quarter 2025. The Company had a lease liability related to this agreement of $24.0 million as of December 31, 2024, which is included in both current and noncurrent "Operating lease liabilities" on the consolidated balance sheets. Payments to Halliburton are included in capital expenditures for oil and natural gas properties in cash flows from investing activities on the consolidated statements of cash flows.
The following table presents the capital expenditures for oil and natural gas properties paid to Halliburton included in the consolidated statements of cash flows for the periods presented:
Nine months ended September 30,
(in thousands)20252024
Capital expenditures for oil and natural gas properties$62,711 $61,176 
Note 14 —Segment reporting
The Company engages in a single activity, the exploration and development of oil and natural gas properties in the Permian Basin of West Texas, and, as such, has one reportable segment based upon the Company’s current organizational and management structure. The accounting policies for the segment, including those related to revenue, are the same as those described in Note 2 in the Company's 2024 Annual Report. Net income (loss), which is reported on the consolidated statements of operations, is the metric most consistent with GAAP that the Company uses to evaluate its performance and make decisions around the timing and allocation of capital investments and debt reduction. The Company does not use a measure of segment assets in its decision making. The Company’s chief operating decision maker (“CODM”) is the Senior Executive Team. There are no significant expense categories regularly provided to the CODM beyond those disclosed in the consolidated statements of operations.
Note 15—Organizational restructuring
In the second quarter of 2025, the Company incurred one-time charges of $4.6 million in connection with an approximate 10% workforce reduction. Such charges comprised of compensation, tax, professional and insurance-related expenses, and are recorded as "Organizational restructuring expenses" on the consolidated statements of operations. All non-vested equity-based compensation awards held by those affected by the workforce reduction were forfeited.

19

20

Index to Consolidated Financial Statements
Page
Report of Independent Registered Public Accounting Firm for the years ended December 31, 2024 and 2023 (PCAOB ID Number 42)
F-2
Consolidated statements of operations
F-5
Consolidated statements of stockholders' equity
F-6
Consolidated statements of cash flows
F-7
Notes to the consolidated financial statements:
F-8
Note 1—Organization
F-8
Note 2—Basis of presentation and significant accounting policies
F-8
Note 3—New accounting standards
F-15
Note 4—Acquisitions and divestitures
F-15
Note 5—Leases
F-20
Note 6—Property and equipment
F-21
Note 7—Debt
F-23
Note 8—Stockholders' equity
F-27
Note 9—Compensation plans
F-28
Note 10—Net income (loss) per common share
F-32
Note 11—Derivatives
F-33
Note 12—Fair value measurements
F-34
Note 13—Income taxes
F-36
Note 14—Credit risk
F-38
Note 15—Commitments and contingencies
F-39
Note 16—Related parties
F-40
Note 17—Segment reporting
F-40
Note 18—Subsequent events
F-40
Unaudited Supplementary Information
F-42
F-1

Report of Independent Registered Public Accounting Firm
To the Stockholders and the Board of Directors of Vital Energy, Inc.
Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of Vital Energy, Inc. (the Company) as of December 31, 2024 and 2023, the related consolidated statements of operations, stockholders' equity and cash flows for each of the three years in the period ended December 31, 2024, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated February 24, 2025 expressed an unqualified opinion thereon.
Basis for opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical audit matters
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
F-2

Depreciation, Depletion, and Amortization (DD&A) of proved properties and Full Cost Ceiling Impairment
Description of the MatterAt December 31, 2024, the carrying value of the Company’s oil and natural gas properties was $4,864 million, depreciation, depletion and amortization (DD&A) expense was $742 million, and the full cost ceiling impairment expense was $481 million for the year then ended. As described in Note 2, the Company follows the full cost method of accounting for its oil and gas properties. Oil and natural gas properties, net, excluding unevaluated properties of $243 million, are depleted using the unit-of-production method based on estimated proved oil, NGL and natural gas reserves. As described in Note 6, the Company’s oil and natural gas properties are subject to the full cost ceiling test under SEC guidelines whereby the Company’s unamortized cost of evaluated oil and natural gas properties are limited to a full cost ceiling based on the estimated future net cash flows from proved oil, NGL and natural gas reserves, discounted at 10%.

The estimation of proved oil, NGL and natural gas reserve volumes is an ongoing process based on technical evaluations, commercial and market assessments, and detailed analysis of well information such as historical production, development and production costs, among other factors. Because of the complexity in estimating oil, NGL and natural gas reserves, management used independent reserve engineers to prepare the proved oil, NGL and natural gas reserve estimates as of December 31, 2024.

Auditing the Company’s DD&A expense and full cost ceiling impairment is complex because of the use of the work of the independent reserve engineers and the evaluation of management’s determination of the inputs including historical production, oil and gas price assumptions, and future operating and capital costs assumptions, among others, used by the engineers in estimating proved oil, NGL and natural gas reserves.
How We Addressed the Matter in Our AuditWe obtained an understanding, evaluated the design, and tested the operating effectiveness of the Company’s controls that address the risks of material misstatement relating to the DD&A expense and full cost ceiling impairment calculation for oil and natural gas properties. This includes controls over the completeness and accuracy of the historical production and financial data used in estimating proved oil, NGL and natural gas reserves.

Our audit procedures included, among others, evaluating the professional qualifications and objectivity of the Company’s independent reserve engineers used to prepare the proved oil, NGL and natural gas reserve estimates. In addition, in assessing whether we can use the work of the independent reserve engineers, we evaluated the completeness and accuracy of the historical production and financial data and inputs, described above used by the engineers in estimating oil, NGL and natural gas reserves by agreeing them to source documentation, and we identified and evaluated corroborative and contrary evidence. For proved undeveloped reserves, we evaluated management’s development plan for compliance with SEC requirements. We also tested the DD&A expense and full cost ceiling impairment calculations for oil and natural gas properties, to conclude they are based on the appropriate proved oil, NGL and natural gas reserve amounts as estimated by the Company’s independent reserve engineers.


/s/ Ernst & Young LLP
We have served as the Company's auditor since 2022.
Tulsa, Oklahoma
February 24, 2025
F-3
Table of ContentsVital Energy, Inc.
Consolidated balance sheets
(in thousands, except share data)December 31, 2024December 31, 2023
Assets
Current assets:
Cash and cash equivalents$40,179 $14,061 
Accounts receivable, net299,698 238,773 
Derivatives101,474 99,336 
Other current assets25,205 18,749 
Total current assets466,556 370,919 
Property and equipment:
Oil and natural gas properties, full cost method:
Evaluated properties13,587,040 11,799,155 
Unevaluated properties not being depleted242,792 195,457 
Less: accumulated depletion and impairment(8,966,200)(7,764,697)
Oil and natural gas properties, net4,863,632 4,229,915 
Midstream and other fixed assets, net134,265 130,293 
Property and equipment, net4,997,897 4,360,208 
Derivatives34,564 51,071 
Operating lease right-of-use assets104,329 144,900 
Deferred income taxes239,685 188,836 
Other noncurrent assets, net35,915 33,647 
Total assets$5,878,946 $5,149,581 
Liabilities and stockholders' equity
Current liabilities:
Accounts payable and accrued liabilities$185,115 $159,892 
Accrued capital expenditures95,593 91,937 
Undistributed revenue and royalties187,563 194,307 
Operating lease liabilities73,143 70,651 
Other current liabilities59,725 78,802 
Total current liabilities601,139 595,589 
Long-term debt, net2,454,242 1,609,424 
Derivatives5,814 — 
Asset retirement obligations82,941 81,680 
Operating lease liabilities26,733 71,343 
Other noncurrent liabilities7,506 6,288 
Total liabilities3,178,375 2,364,324 
Commitments and contingencies
Stockholders' equity:
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero and 595,104 issued and outstanding as of December 31, 2024 and 2023, respectively
— 6 
Common stock, $0.01 par value, 80,000,000 shares authorized, and 38,144,248 and 35,413,551 issued and outstanding as of December 31, 2024 and 2023, respectively
381 354 
Additional paid-in capital3,823,241 3,733,775 
Accumulated deficit(1,123,051)(948,878)
Total stockholders' equity2,700,571 2,785,257 
Total liabilities and stockholders' equity$5,878,946 $5,149,581 
The accompanying notes are an integral part of these consolidated financial statements.
F-4
Table of ContentsVital Energy, Inc.
Consolidated statements of operations
Years ended December 31,
(in thousands, except per share data)202420232022
Revenues:
Oil sales$1,728,971 $1,328,518 $1,351,207 
NGL sales190,775 136,901 234,613 
Natural gas sales15,544 63,214 208,554 
Sales of purchased oil12,745 14,313 119,408 
Other operating revenues4,279 4,658 7,014 
Total revenues1,952,314 1,547,604 1,920,796 
Costs and expenses:
Lease operating expenses448,078 261,129 173,983 
Production and ad valorem taxes117,947 93,224 110,997 
Oil transportation and marketing expenses44,843 41,284 53,692 
Gas gathering, processing and transportation expenses17,825 2,013 — 
Costs of purchased oil13,243 15,065 122,118 
General and administrative101,578 104,819 68,082 
Organizational restructuring expenses795 1,654 10,420 
Depletion, depreciation and amortization741,966 463,244 311,640 
Impairment expense481,305 — 40 
Other operating expenses, net8,799 6,223 8,583 
Total costs and expenses1,976,379 988,655 859,555 
Gain (loss) on disposal of assets, net1,513 672 (1,079)
Operating income (loss)(22,552)559,621 1,060,162 
Non-operating income (expense):
Gain (loss) on derivatives, net38,140 96,230 (298,723)
Interest expense(177,794)(149,819)(125,121)
Loss on extinguishment of debt, net(66,115)(4,039)(1,459)
Other income, net7,060 9,748 2,155 
Total non-operating expense, net(198,709)(47,880)(423,148)
Income (loss) before income taxes(221,261)511,741 637,014 
Income tax benefit (expense)47,740 183,337 (5,502)
Net income (loss) (173,521)695,078 631,512 
Preferred stock dividends(652)(449)— 
Net income (loss) available to common stockholders$(174,173)$694,629 $631,512 
Net income (loss) per common share:
Basic$(4.74)$34.30 $37.88 
Diluted$(4.74)$33.44 $37.44 
Weighted-average common shares outstanding:
Basic36,725 20,254 16,672 
Diluted36,725 20,783 16,867 
The accompanying notes are an integral part of these consolidated financial statements.
F-5
Table of ContentsVital Energy, Inc.
Consolidated statements of stockholders' equity
Preferred stockCommon stockAdditional
paid-in
capital		Treasury stock
(at cost)		Accumulated deficitTotal
(in thousands)SharesAmountSharesAmountSharesAmount
Balance, December 31, 2021— $— 17,075 $171 $2,788,628 — $— $(2,275,019)$513,780 
Restricted stock awards— — 255 3 (3)— — — — 
Restricted stock forfeitures— — (58)(1)1 — — — — 
Share repurchases— — (491)(5)(37,285)491 37,290 — — 
Stock exchanged for tax withholding— — (94)(1)(7,441)94 7,442 — — 
Retirement of treasury stock— — — — — (585)(44,732)— (44,732)
Share-settled equity-based compensation— — — — 10,186 — — — 10,186 
Performance share conversion— — 75 1 (1)— — — — 
Net income— — — — — — — 631,512 631,512 
Balance, December 31, 2022— — 16,762 168 2,754,085 — — (1,643,507)1,110,746 
Restricted stock awards— — 340 3 (3)— — — — 
Restricted stock forfeitures— — (47)— — — — — — 
Stock exchanged for tax withholding— — (59)(1)(3,076)59 3,077 — — 
Retirement of treasury stock— — — — — (59)(3,077)— (3,077)
Share-settled equity-based compensation— — — — 13,969 — — — 13,969 
Issuance of common stock, net of costs— — 3,163 32 161,191 — — — 161,223 
Equity issued for acquisition of oil and natural gas properties6,726 67 9,124 91 807,609 — — — 807,767 
Preferred stock conversion(6,131)(61)6,131 61 — — — — — 
Preferred stock dividend paid— — — — — — — (449)(449)
Net income— — — — — — — 695,078 695,078 
Balance, December 31, 2023595 6 35,414 354 3,733,775 — — (948,878)2,785,257 
Restricted stock awards— — 484 5 (5)— — — — 
Restricted stock forfeitures— — (51)(1)1 — — — — 
Stock exchanged for tax withholding— — (76)(1)(3,568)76 3,569 — — 
Retirement of treasury stock— — — — — (76)(3,569)— (3,569)
Share-settled equity-based compensation— — — — 18,336 — — — 18,336 
Equity issued for acquisition of oil and natural gas properties980 10 803 8 74,910 — — — 74,928 
Preferred stock conversion(1,575)(16)1,575 16 — — — — — 
Preferred stock dividend paid— — — — — — — (652)(652)
Other— — (5)— (208)— — — (208)
Net loss— — — — — — — (173,521)(173,521)
Balance, December 31, 2024— $— 38,144 $381 $3,823,241 — $— $(1,123,051)$2,700,571 
The accompanying notes are an integral part of these consolidated financial statements.
F-6
Table of ContentsVital Energy, Inc.
Consolidated statements of cash flows
Years ended December 31,
(in thousands)202420232022
Cash flows from operating activities:
Net income (loss)$(173,521)$695,078 $631,512 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Share-settled equity-based compensation, net14,646 10,994 8,403 
Depletion, depreciation and amortization741,966 463,244 311,640 
Impairment expense481,305 — 40 
Mark-to-market on derivatives:
(Gain) loss on derivatives, net(38,140)(96,230)298,723 
Settlements received (paid) for matured derivatives, net58,322 (17,648)(486,173)
Loss on extinguishment of debt, net66,115 4,039 1,459 
Deferred income tax benefit(50,196)(189,060)(619)
Other, net27,663 13,983 35,532 
Changes in operating assets and liabilities:
Accounts receivable, net(61,163)(77,742)(9,226)
Other current assets(6,456)(2,754)8,370 
Other noncurrent assets, net(1,151)484 1,837 
Accounts payable and accrued liabilities12,803 52,763 31,534 
Undistributed revenue and royalties(29,762)(31,907)42,085 
Other current liabilities(25,004)(5,656)(18,503)
Other noncurrent liabilities(17,097)(6,632)(26,994)
Net cash provided by operating activities1,000,330 812,956 829,620 
Cash flows from investing activities:
Acquisitions of oil and natural gas properties(850,911)(849,508)(5,581)
Capital expenditures:
Oil and natural gas properties(864,437)(617,397)(566,989)
Midstream and other fixed assets(23,341)(14,021)(14,147)
Proceeds from dispositions of capital assets, net of selling costs2,874 2,403 108,888 
Other investing activities(1,776)2,393 1,877 
Net cash used in investing activities(1,737,591)(1,476,130)(475,952)
Cash flows from financing activities:
Borrowings on Senior Secured Credit Facility1,750,000 765,000 455,000 
Payments on Senior Secured Credit Facility(1,005,000)(700,000)(490,000)
Issuance of senior unsecured notes1,001,500 897,710 — 
Extinguishment of debt(952,214)(457,792)(282,902)
Proceeds from issuance of common stock, net of offering costs— 161,223 — 
Share repurchases— — (37,290)
Stock exchanged for tax withholding(3,569)(3,077)(7,442)
Payments for debt issuance costs(22,078)(27,011)(1,938)
Other, net(5,260)(3,253)(1,459)
Net cash provided by (used in) financing activities763,379 632,800 (366,031)
Net increase (decrease) in cash and cash equivalents26,118 (30,374)(12,363)
Cash and cash equivalents, beginning of period14,061 44,435 56,798 
Cash and cash equivalents, end of period$40,179 $14,061 $44,435 
The accompanying notes are an integral part of these consolidated financial statements.
F-7
Table of ContentsVital Energy, Inc.
Notes to the consolidated financial statements
Notes to the consolidated financial statements
Note 1
Organization
Vital Energy, Inc. ("Vital Energy" or the "Company"), together with its wholly-owned subsidiaries, is an independent energy company focused on the acquisition, exploration and development of oil and natural gas properties in the Permian Basin of West Texas. In these notes, the "Company" refers to Vital Energy and its subsidiaries collectively, unless the context indicates otherwise. All amounts, dollars and percentages presented in these consolidated financial statements and the related notes are rounded and, therefore, approximate.
Note 2
Basis of presentation and significant accounting policies
Basis of presentation
The accompanying consolidated financial statements were derived from the historical accounting records of the Company and reflect the historical financial position, results of operations and cash flows for the periods described herein. The accompanying consolidated financial statements have been prepared in accordance with GAAP. All material intercompany transactions and account balances have been eliminated in the consolidation of accounts.
Use of estimates in the preparation of consolidated financial statements
The preparation of the accompanying consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions about future events. These estimates and the underlying assumptions 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 revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ.
Significant estimates include, but are not limited to, (i) volumes of the Company's reserves of oil, NGL and natural gas, (ii) future cash flows from oil and natural gas properties, (iii) impairments and (iv) fair values of assets acquired and liabilities assumed in a business combination. As fair value is a market-based measurement, it is determined based on the assumptions that would be used by market participants. These estimates and assumptions are based on management's best judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment. Such estimates and assumptions are adjusted when facts and circumstances dictate. Illiquid credit markets and volatile equity and energy markets may increase the uncertainty inherent in such estimates and assumptions. Management believes its estimates and assumptions to be reasonable under the circumstances. As future events and their effects cannot be determined with precision, actual values and results could differ from these estimates. Any changes in estimates resulting from future changes in the economic environment will be reflected in the financial statements in future periods.
Cash and cash equivalents
The Company defines cash and cash equivalents to include cash on hand, cash in bank accounts and highly liquid investments with original maturities of three months or less. The Company maintains cash and cash equivalents in bank deposit accounts and money market funds that may not be federally insured. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on such accounts. See Note 14 for discussion regarding the Company's exposure to credit risk.
Accounts receivable
The Company sells its produced oil, NGL and natural gas and purchased oil to various customers and participates with other parties in the development and operation of oil and natural gas properties.
The Company maintains an allowance for expected credit losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers significant factors such as historical losses, current receivables aging, the debtors' current ability to pay its obligation to the Company and existing industry and economic data. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is remote,
F-8
Table of ContentsVital Energy, Inc.
Notes to the consolidated financial statements
and payments subsequently received on such balances are credited to the allowance. See Note 14 for discussion regarding the Company's exposure to credit risk.
Accounts receivable consisted of the following components as of the dates presented:
(in thousands)December 31, 2024December 31, 2023
Oil, NGL and natural gas sales(1)
$180,248 $173,917 
Joint operations, net91,949 60,397 
Other27,501 4,459 
Total accounts receivable, net$299,698 $238,773 
_____________________________________________________________________________
(1)For purchasers that the Company has netting arrangements with, the amounts presented include the net positions.
Derivatives
Derivatives are recorded at fair value and are presented on a net basis in "Derivatives" on the consolidated balance sheets as assets and/or liabilities. The Company records the fair value of derivatives on a net basis by counterparty where the right of offset exists. The Company determines the fair value of its derivatives using fair value hierarchy level inputs to its valuation techniques. The Company's derivatives were not designated as hedges for accounting purposes, and the Company does not enter into such instruments for speculative trading purposes. Accordingly, the changes in fair value are recognized in "Gain (loss) on derivatives, net" under "Non-operating income (expense)" on the consolidated statements of operations. See Notes 11 and 12 for additional discussion of derivatives and their fair value measurement on a recurring basis, respectively.
Other current assets and liabilities
Other current assets consisted of the following components as of the dates presented:
(in thousands)December 31, 2024December 31, 2023
Prepaid expenses and other$7,916 $5,026 
Inventory17,289 13,723 
Total other current assets$25,205 $18,749 
Other current liabilities consisted of the following components as of the dates presented:
(in thousands)December 31, 2024December 31, 2023
Accrued interest payable$34,988 $52,837 
Accrued compensation and benefits12,397 19,547 
Other liabilities12,340 6,418 
Total other current liabilities$59,725 $78,802 
Oil and natural gas properties
The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain employee-related costs, incurred for the purpose of acquiring, exploring for or developing oil and natural gas properties, are capitalized and, once evaluated, depleted on a composite unit-of-production method based on estimates of proved oil, NGL and natural gas reserves. The depletion base includes estimated future development costs and dismantlement, restoration and abandonment costs, net of estimated salvage values. Capitalized costs include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Costs, including employee-related costs, associated with production and general corporate activities are expensed in the period incurred.
The Company excludes unevaluated property acquisition costs and exploration costs from the depletion calculation until it is determined whether or not proved reserves can be assigned to the properties. The Company capitalizes a portion of its interest costs to its unevaluated properties and such costs become subject to depletion when proved reserves can be assigned to the associated properties. All items classified as unevaluated properties are assessed on a quarterly basis for
F-9
Table of ContentsVital Energy, Inc.
Notes to the consolidated financial statements
possible impairment. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling capital investments to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion and the full cost ceiling test.
Sales of oil and natural gas properties, whether or not being depleted currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, NGL and natural gas. See Note 6 for additional discussion of the Company's oil and natural gas properties and other property and equipment.
Leases
The Company recognizes operating lease right-of-use assets and operating lease liabilities on the consolidated balance sheets for operating leases with an initial term greater than 12 months.
The Company determines whether a contract is or contains a lease at inception of the contract, based on answers to a series of questions that address whether an identified asset exists and whether the Company has the right to obtain substantially all of the benefit of the asset and to control its use over the full term of the agreement. Unless implicitly defined, the Company determines the present value of future lease payments using an estimated incremental borrowing rate.
The Company has recognized operating lease right-of-use assets and operating lease liabilities on the consolidated balance sheets for leases of commercial real estate with lease terms extending into 2033 and drilling, completion, production and other equipment leases with lease terms extending into 2027. The Company has various other drilling, completion and production equipment leases on a short-term basis which are reflected in short-term lease costs.
The Company's lease costs include those that are recognized in net income during the period and capitalized as part of the cost of another asset in accordance with other GAAP. The lease costs related to drilling, completion and production activities are reflected at the Company's net ownership, which is consistent with the principals of proportional consolidation, and lease commitments are reflected on a gross basis.
Certain of the Company's operating lease right-of-use asset classes include options to renew on a month-to-month basis. The Company considers contract-based, asset-based, market-based and entity-based factors to determine the term over which it is reasonably certain to extend the lease in determining its right-of-use assets and liabilities.
See Note 5 for further discussion of the Company's leases.
Inventory
The Company has the following types of inventory: (i) materials and supplies inventory used in production activities of oil and natural gas properties and midstream service assets and (ii) line-fill in third-party pipelines, which is the minimum volume of product in a pipeline system that enables the system to operate, and is generally not available to be withdrawn from the pipeline until the expiration of the transportation contract. All inventory is carried at the lower of cost or net realizable value ("NRV"), with cost determined using the weighted-average cost method, and is included in "Other current assets" and "Other noncurrent assets, net" on the consolidated balance sheets. The NRV for materials and supplies inventory is estimated utilizing a replacement cost approach (Level 2). The NRV for line-fill in third-party pipelines is estimated utilizing a quoted market price adjusted for regional price differentials (Level 2). See Note 12 for discussion of the fair value hierarchy.
Debt issuance costs
Debt issuance costs, which are recorded at cost, net of amortization, are amortized over the life of the respective debt agreements utilizing the straight-line method. See Note 7 for additional discussion of the Company's debt issuance costs.
Asset retirement obligations
Asset retirement obligations associated with the retirement of tangible long-lived assets are recognized as a liability in the period in which they are incurred and become determinable. The associated asset retirement costs are part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related long-
F-10
Table of ContentsVital Energy, Inc.
Notes to the consolidated financial statements
lived asset is expensed through depletion, or for midstream service assets through depreciation. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and accretion expense.
The fair value of additions to the asset retirement obligation liability is measured using valuation techniques consistent with the income approach, which converts future cash flows into a single discounted amount. Significant inputs to the valuation include: (i) estimated plug and abandonment or removal and remediation cost per well and related facilities or midstream service asset based on Company experience, if any, in accordance with applicable state laws, (ii) estimated remaining life per well or midstream service asset, (iii) future inflation factors and (iv) the Company's average credit-adjusted risk-free rate. Inherent in the fair value calculation of asset retirement obligations are numerous assumptions and judgments including, in addition to those noted above, the ultimate settlement of these amounts, the ultimate timing of such settlement and changes in technology, regulatory, political, environmental, safety and public relations matters. To the extent future revisions to these assumptions impact the fair value of the existing asset retirement obligation liability, an adjustment will be made to the asset balance.
The Company is obligated by contractual and regulatory requirements to remove certain midstream service assets and perform other remediation of the sites where such midstream service assets are located upon the retirement of those assets. However, the fair value of the asset retirement obligation cannot currently be reasonably estimated because the settlement dates are indeterminate. The Company will record an asset retirement obligation for midstream service assets in the periods in which settlement dates are reasonably determinable.
The following table presents changes to the Company's asset retirement obligations liability for the periods presented:
Years ended December 31,
(in thousands)20242023
Liability at beginning of year$84,324 $74,081 
Liabilities added due to acquisitions, drilling, midstream service asset construction and other3,978 7,648 
Accretion expense(1)
4,209 3,703 
Liabilities settled due to plugging and abandonment or removed due to sale(3,124)(1,108)
Revision of estimates105 — 
Liability at end of year89,492 84,324 
Less: current asset retirement obligations(2)
6,551 2,644 
Non-current asset retirement obligations$82,941 $81,680 
______________________________________________________________________________
(1)Accretion expense is included in "Other operating expenses, net" on the consolidated statements of operations.
(2)Current asset retirement obligations is included in "Other current liabilities" on the consolidated balance sheets.
Fair value measurements
The carrying amounts reported on the consolidated balance sheets for cash and cash equivalents, accounts receivable, accounts payable, accrued capital expenditures, undistributed revenue and royalties and other accrued assets and liabilities approximate their fair values. See Inventory in Note 2 for the fair value assumptions used in estimating the NRV of inventory, which is used to determine the necessity for any inventory impairment. See Note 4 for the fair value assumptions used in estimating the fair values of assets acquired and liabilities assumed in the Company's acquisitions. See Note 12 for further discussion of fair value measurements.
Treasury stock
Treasury stock is recorded at cost, which includes incremental direct transaction costs, and is retired upon acquisition as a result of (i) stock exchanged to satisfy tax withholding that arises upon the lapse of restrictions on share-settled equity-based awards at the awardee's election, (ii) stock exchanged for the cost of exercise of stock options at the awardee's election, or (iii) the Company's open market repurchases of its common stock.

F-11
Table of ContentsVital Energy, Inc.
Notes to the consolidated financial statements
Revenue recognition
Oil, NGL and natural gas sales and sales of purchased oil are generally recognized at the point in time that control of the product is transferred to the customer.
Oil sales and sales of purchased oil
Under its oil sales contracts, the Company sells produced or purchased oil at the delivery point specified in the contract and collects an agreed-upon index price, net of pricing differentials. The delivery point may be at the wellhead, the inlet of the purchaser's pipeline or nominated pipeline or the Company's truck unloading facility. At the delivery point, the purchaser typically takes custody, title and risk of loss of the product and, therefore, control as defined under applicable GAAP, typically passes at the delivery point. The Company recognizes revenue at the net price received when control transfers to the purchaser.
The Company engages in transactions in which it sells oil at the lease and subsequently repurchases the same volume of oil from that customer at a downstream delivery point under a separate agreement ("Repurchase Agreement") for use in the sale to the final customer. The commercial reasoning for such transactions may vary. Where a Repurchase Agreement exists, the Company must evaluate whether the customer obtains control of the oil at the lease and therefore whether it is appropriate to recognize revenue for the lease sale. Where the Company has an obligation or a right to repurchase the oil, the customer does not obtain control of the oil because it is limited in its ability to direct the use of, and obtain substantially all of the remaining benefits from the oil even though it may have physical possession of the oil. When the Company repurchases the oil for equal to or more than the original selling price, then the transaction represents a financing arrangement unless there is only a short passage of time between the sale and repurchase, in which case any excess amount paid represents an expense associated with the sale of oil to the final customer. The Company recognizes such repurchase expense and any transportation expenses incurred for the delivery of the oil to the final customer in the "Transportation and marketing expenses" line item in the accompanying consolidated statements of operations.
In certain situations, the Company enters into purchase and sale transactions of oil inventory with the same counterparty in contemplation with one another, and these transactions are presented on the consolidated statements of operations on a net basis in accordance with GAAP. The following table presents the net effect of these transactions for the periods presented:
Years ended December 31,
(in thousands)202420232022
Sales of purchased oil inventory$249,396 $494,860 $104,403 
Purchased oil inventory249,955 495,697 104,039 
Net effect on earnings(1)
$(559)$(837)$364 
______________________________________________________________________________
(1)Amounts presented are recorded in "Sales of purchased oil" in the consolidated statements of operations.
Under certain of its customer contracts, the Company is subject to contractual penalties if it fails to deliver contractual minimum volumes to its customers. Such amounts are recorded as a reduction to the transaction price as these amounts do not represent payments to the customer for distinct goods or services and instead relate specifically to the failure to perform under the specific customer contract. Such amounts are recorded as a reduction to the transaction price when payment is determined as probable, typically when such a deficiency occurs.
NGL and natural gas sales
Under its natural gas processing contracts, the Company delivers produced natural gas to a midstream processing entity at the wellhead or the inlet of the processing entity's system. The processing entity processes the natural gas, sells the resulting NGL and residue gas to third parties and pays the Company for the NGL and residue gas with deductions that may include gathering, compression, processing and transportation fees. In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. For contracts where the Company has concluded that it is the agent in the ultimate sale to the third party and the midstream processing entity is the principal and that the Company has transferred control of unprocessed natural gas to the midstream processing entity, the Company recognizes revenue based on the net amount of the proceeds received from the midstream processing entity who represents the Company's customer. For contracts where the Company has concluded that it is the principal with the ultimate third party being the customer, and control of the NGL or
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Table of ContentsVital Energy, Inc.
Notes to the consolidated financial statements
residue gas transferring at the tailgate of the midstream entity's processing plant, the Company recognizes revenue for those contracts on a gross basis, with gathering, compression, processing, and transportation fees presented as an expense.
Significant judgments
The Company engages in various types of transactions in which unaffiliated midstream entities process the Company's liquids-rich natural gas and, in some scenarios, subsequently market resulting NGL and residue gas to third-party customers on the Company's behalf. These types of transactions require judgment to determine whether the Company is the principal or the agent in the contract and, as a result, whether revenues are recorded gross or net. For existing contracts, the Company has determined that it serves as the agent in the sale of products under certain natural gas processing and marketing agreements with unaffiliated midstream entities in accordance with the control model under applicable GAAP. As a result, the Company presents revenue on a net basis for amounts expected to be received from third-party customers through the marketing process, with expenses and deductions incurred subsequent to control of the product(s) transferring to the unaffiliated midstream entity being netted against revenue.
Transaction price allocated to remaining performance obligations
A significant number of the Company's product sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient under applicable GAAP that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.
For the Company's product sales that have a contract term greater than one year, the Company has utilized the practical expedient under applicable GAAP that states that it is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under the Company's product sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied. Under these contracts each unit of service represents a separate performance obligation and therefore performance obligations in respect of future services are wholly unsatisfied.
Contract balances
Under the Company's customer contracts, invoicing occurs once the Company's performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company's contracts do not give rise to contract assets or contract liability balances.
Prior-period performance obligations
For sales of oil, NGL, natural gas and purchased oil, the Company records revenue in the month production is delivered to the purchaser. However, settlement statements and payment may not be received for 30 to 90 days after the date production is delivered and, as a result, the Company is required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales once payment is received from the purchaser. Such differences have historically not been significant. The Company uses knowledge of its properties, its properties' historical performance, spot market prices and other factors as the basis for these estimates. For the years ended December 31, 2024, 2023 and 2022, revenue recognized related to performance obligations satisfied in prior reporting periods was not material.
Equity-based compensation awards
Equity-based compensation expense is included in "General and administrative" on the consolidated statements of operations, and includes expense for (i) restricted stock awards and share-settled performance share unit awards, which are accounted for as equity awards and are generally based on the awards' grant date or modification date fair value less an expected forfeiture rate and (ii) cash-settled performance share unit awards, which are accounted for as liability awards and are re-measured at each quarterly reporting period until settlement. The Company capitalizes a portion of equity-based compensation for employees who are directly involved in the acquisition, exploration and development of its oil and natural gas properties into the full cost pool. Capitalized equity-based compensation is included in "Evaluated properties" on the consolidated balance sheets. See Note 9 for further discussion of the Company's Equity Incentive Plan.
Organizational restructurings
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Table of ContentsVital Energy, Inc.
Notes to the consolidated financial statements
Organizational restructuring expenses are separation charges comprised of compensation, tax, professional, outplacement and insurance-related expenses, which are recorded as "Organizational restructuring expenses" on the consolidated statements of operations.
Income taxes
Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating losses and tax credit carryforwards. Under this method, 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 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 or loss in the period that includes the enactment date.
The Company evaluates uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, the Company determines whether it is more-likely-than-not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more-likely-than-not threshold is measured to determine the amount of benefit to be recognized in the consolidated financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. The Company has no unrecognized tax benefits related to uncertain tax positions in the consolidated financial statements at December 31, 2024 or 2023. See Note 13 for additional information regarding the Company's income taxes.
Supplemental cash flow and non-cash information
The following table presents supplemental cash flow and non-cash information for the periods presented:
Years ended December 31,
(in thousands)202420232022
Supplemental cash flow information:
Cash paid for interest, net of $1,413, $2,892 and $3,872 of capitalized interest, respectively(1)
$187,483 $132,986 $131,867 
Supplemental non-cash operating information:
Right-of-use assets obtained in exchange for operating lease liabilities(2)
$49,683 $176,027 $34,532 
Supplemental non-cash investing information:
Change in accrued capital expenditures$3,656 $43,559 $(2,207)
Equity issued for acquisition of oil and natural gas properties(3)
$74,928 $807,767 $— 
Liabilities assumed in acquisitions of oil and natural gas properties(3)
$37,090 $86,478 $— 
______________________________________________________________________________
(1)See Note 7 for additional discussion of the Company's interest expense.
(2)See Note 5 for additional discussion of the Company's leases.
(3)See Notes 4 and 8 for additional discussion of the Company's acquisitions of oil and natural gas properties and equity issued in connection with such acquisitions, respectively.
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Table of ContentsVital Energy, Inc.
Notes to the consolidated financial statements
Note 3
New accounting standards
The Company considered the applicability and impact of all accounting standard updates ("ASU") issued by the Financial Accounting Standards Board ("FASB") to the Accounting Standards Codification.
ASUs not yet adopted
In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures, which requires more detailed tax disclosures, including disaggregated information about an entity's effective tax rate reconciliation as well as expanded information on income taxes paid by jurisdiction. The amendments in this accounting standard are effective, on a prospective basis, for fiscal years beginning after December 15, 2024. Early adoption is permitted. Adoption of this ASU will result in additional disclosure, but will not impact the Company’s consolidated financial position, results of operations or cash flows.
In November 2024, the FASB issued ASU 2024-03, Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses, which requires additional disclosure about specific types of expenses included in the expense captions presented on the income statement. The amendments in this accounting standard are effective, on a prospective basis, for fiscal years beginning after December 15, 2026, and interim periods beginning after December 15, 2027. Early adoption is permitted. Adoption of this ASU will result in additional disclosure, but will not impact the Company's consolidated financial position, results of operations or cash flows.
Recently adopted ASU
During the year ended December 31, 2024, the Company adopted ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures, which sets forth improvements to the current segment disclosure requirements in accordance with Topic 280 "Segment Reporting," including clarifying that entities with a single reportable segment are subject to both new and existing segment reporting requirements. ASU 2023-07 is effective for interim periods beginning after December 15, 2024, and is applied retrospectively to all periods presented in this Annual Report. Adoption of this ASU results in additional disclosure, but did not impact the Company's consolidated financial position, results of operations or cash flows. See Note 17 for additional information.
Note 4
Acquisitions and divestitures
2024 asset acquisitions
Point Acquisition
On September 20, 2024 (the "Point Closing Date"), the Company, together with Northern Oil and Gas, Inc. ("NOG"), purchased certain oil and natural gas properties located in the Delaware Basin with an effective date of April 1, 2024 from Point Energy Partners Petroleum, LLC, Point Energy Partners Operating, LLC, Point Energy Partners Water, LLC and Point Energy Partners Royalty, LLC (collectively, “Point”) for an aggregate purchase price of $1.0 billion in cash, including customary closing adjustments (the "Point Acquisition"). The Company purchased 80% of the acquired assets, consisting of approximately 16,300 net acres in Ward and Winkler Counties, and will operate the assets, and NOG purchased the remaining 20% of the assets.
The Company's portion of the aggregate preliminary purchase price was $827.0 million, which consisted of (i) $805.1 million in cash and (ii) $21.9 million of estimated transaction-related expenses. The purchase price is subject to additional post-closing adjustments. The Point Acquisition was accounted for as an asset acquisition, as substantially all the gross assets acquired are concentrated in a group of similar identifiable assets. Based on the relative fair values on the Point Closing Date, the acquired assets and liabilities assumed were allocated as follows: (i) $793.9 million to evaluated properties, (ii) $52.9 million to unevaluated properties, of which $48.6 million remained as of December 31, 2024, (iii) $14.3 million to revenue suspense liabilities, (iv) $3.0 million to asset retirement obligation liabilities and (v) $2.5 million to property tax liabilities.
PEP Acquisition
On February 2, 2024 (the "PEP Closing Date"), the Company purchased additional working interests in producing properties associated with the Henry Acquisition (as defined herein), with an effective date of August 1, 2023 (the "PEP Acquisition")
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Table of ContentsVital Energy, Inc.
Notes to the consolidated financial statements
through PEP Henry Production Partners LP, PEP HPP Jubilee SPV LP, PEP PEOF Dropkick SPV, LLC, PEP HPP Dropkick SPV LP and HPP Acorn SPV LP.
The aggregate purchase price of $77.6 million consisted of (i) 878,690 shares of the Company's common stock, par value $0.01 per share ("Common Stock") based upon the share price as of the PEP Closing Date, (ii) 980,272 shares of the Company's 2.0% Cumulative Mandatorily Convertible Series A Preferred Stock, par value $0.01 per share ("Preferred Stock") based upon the share price as of the PEP Closing Date, (iii) $1.8 million cash consideration received for closing adjustments and (iv) $0.7 million in transaction-related expenses. The purchase price is inclusive of final closing adjustments. The PEP Acquisition was accounted for as an asset acquisition, as substantially all the gross assets acquired are concentrated in a group of similar identifiable assets. Based on the relative fair values on PEP Closing Date, the acquired assets assumed were allocated as follows: (i) $77.7 million to evaluated properties, (ii) $0.3 million to unevaluated properties, all of which remained as of December 31, 2024, and (iii) $0.4 million to asset retirement obligations. The 980,272 shares of Preferred Stock were subsequently converted to an equal number of shares of Common Stock on May 23, 2024. See Note 8 for further discussion of the Preferred Stock conversion.
2023 business combination
Henry Acquisition
On September 13, 2023, the Company entered into a purchase and sale agreement (the “Henry PSA”) with Henry Resources, LLC, Henry Energy LP and Moriah Henry Partners LLC (collectively, “Henry”), pursuant to which the Company agreed to purchase (the “Henry Acquisition”) Henry’s oil and gas properties in the Midland and Delaware Basin, including approximately 15,900 net acres located in Midland, Reeves and Upton Counties, equity interests in certain subsidiaries and related assets and contracts.
On November 5, 2023 ("Henry Closing Date"), the Company closed the Henry Acquisition. The following table presents components of the consideration paid in the Henry Acquisition, which is inclusive final closing adjustments:
(in thousands, except for share and share price data)
As of November 5, 2023
Shares of Company common stock issued
2,145,725
Company common stock price on Henry Closing Date
$52.25 
Fair value of Company common stock issued
$112,114 
Shares of Company preferred stock issued
6,131,381
Company preferred stock price on Henry Closing Date
$52.25 
Fair value of Company preferred stock issued (before dividends)
$320,365 
Fair value of preferred stock dividends
446 
Fair value of Company preferred stock issued
$320,811 
Cash consideration for working capital closing adjustments
4,359 
Total consideration
$437,284 

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Table of ContentsVital Energy, Inc.
Notes to the consolidated financial statements
The Henry Acquisition was accounted for as a business combination, with all associated transaction costs of $11.4 million included in "General and administrative expense" on the consolidated statements of operations. The following table presents the final purchase price allocation of the Henry Acquisition to the assets acquired and liabilities assumed, based on their fair values on the Henry Closing Date:
(in thousands)
As of November 5, 2023
Fair value of assets acquired:
Oil and natural gas properties:
Evaluated properties$384,417 
Unevaluated properties(1)
70,124 
Operating lease right-of-use assets3,366 
Fair value of liabilities assumed:
Asset retirement obligations
(1,211)
Operating lease liabilities(3,366)
Revenue suspense liabilities(16,046)
Total purchase price$437,284 
______________________________________________________________________________
(1)As of December 31, 2023, $27.3 million remained in unevaluated properties.
The Company conducted assessments of recognized amounts for identifiable assets acquired and liabilities assumed in the Henry Acquisition at the estimated acquisition date fair values. The Company makes various assumptions in estimating the fair values of assets acquired and liabilities assumed. The most significant assumptions relate to the estimated fair values of evaluated and unevaluated oil and natural gas properties. The fair values of these properties were measured using an income approach utilizing the discounted cash flow model that converts future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) forecasted oil, NGL and natural gas reserve quantities; (ii) future commodity strip prices as of the closing dates adjusted for transportation and regional price differentials; (iii) forecasted ad valorem taxes, production taxes, income taxes, operating expenses and development costs; and (iv) a peer group weighted-average cost of capital rate subject to additional project-specific risk factors. To compensate for the inherent risk of estimating the value of the unevaluated properties, the discounted future net revenues of proved undeveloped and probable reserves are reduced by additional reserve adjustment factors. These assumptions represent Level 3 inputs under the fair value hierarchy, as described in Note 12.
The Company's consolidated statement of operations for the year ended December 31, 2023 includes revenues of $28.8 million and net income of $13.8 million attributable to the Henry Acquisition, subsequent to the Henry Closing Date.
Pro forma financial information (unaudited)
The following unaudited summary financial information for the years ended December 31, 2023 and 2022 gives effect to the Henry Acquisition as if they had been completed on January 1, 2022. The unaudited pro forma financial information is provided for illustrative purposes only and does not purport to represent what the actual consolidated results of operations or the consolidated financial position of Vital Energy would have been had the Henry Acquisition and related financing occurred on the date noted above, nor are they necessarily indicative of future consolidated results of operations or consolidated financial position.    
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Table of ContentsVital Energy, Inc.
Notes to the consolidated financial statements
The below information reflects pro forma adjustments for the issuance of the Company's common stock and preferred stock as consideration for the Henry Acquisition, as well as pro forma adjustments based on available information and certain assumptions the Company believes are reasonable, including adjustments to depreciation, depletion and amortization based on the full cost method of accounting and estimated impacts of the pro forma adjustments to income tax and valuation allowance.
Years ended December 31,
(in thousands)20232022
Total revenues$1,701,019 $2,206,570 
Operating income$632,666 $1,225,218 
Net income$716,775 $791,740 
Net income available to common shareholders$710,560 $785,001 
Net income per common share:
Basic$31.72 $41.72 
Diluted$25.51 $31.49 
2023 asset acquisitions
Grey Rock Acquisition
On December 21, 2023 (the "Grey Rock Closing Date"), the Company purchased additional working interests in producing assets associated with the Henry Acquisition, with an effective date of December 21, 2023 (the "Grey Rock Acquisition") through Granite Ridge Holdings LLC, GREP IV-A Permian, LLC and GREP IV-B Permian, LLC (collectively, “Grey Rock”).
The aggregate purchase price of $56.5 million consisted of (i) 627,026 shares of the Company's common stock, par value $0.01 per shares ("Common Stock") based upon the share price as of the Grey Rock Closing Date, ii) 595,104 shares of the Company's 2.0% Cumulative Mandatorily Convertible Series A Preferred Stock, par value $0.01 per shares ("Preferred Stock") based upon the share price as of the Grey Rock Closing Date and (iii) $1.2 million in post-close adjustments and transaction-related expenses. The purchase price is inclusive of final closing adjustments. The Grey Rock Acquisition was accounted for as an asset acquisition, as substantially all the gross assets acquired are concentrated in a group of similar identifiable assets. Based on the relative fair values on Grey Rock Closing Date, the acquired assets and liabilities assumed were allocated as follows: (i) $53.3 million to evaluated properties, (ii) $3.3 million to unevaluated properties, all of which remained as of December 31, 2023 and (iii) $0.1 million to asset retirement obligation liabilities. The 595,104 shares of Preferred Stock were subsequently converted to an equal number of shares of Common Stock on May 23, 2024. See Note 8 for further discussion of the Preferred Stock conversion.
Tall City Acquisition
On November 6, 2023 ("Tall City Closing Date"), the Company purchased certain oil and gas properties in the Delaware Basin, including approximately 21,450 net acres located in Reeves County and related assets and contracts, with an effective date September 13, 2023 (the "Tall City Acquisition") from Tall City Property Holdings III LLC and Tall City Operations III LLC (collectively, "Tall City").
The aggregate purchase price of $360.4 million consisted of (i) $280.6 million in cash, (ii) 1,402,258 shares of Common Stock based upon the share price as of the Tall City Closing Date and (iii) $9.0 million in transaction-related expenses. The purchase price is inclusive of final closing adjustments. Upon entering into the purchase and sale agreement with Tall City (the "Tall City PSA"), the Company issued Common Stock as a deposit to be held in escrow until closing of the Tall City Acquisition, of which certain shares remain in escrow to satisfy potential indemnification claims under the Tall City PSA. See Note 8 for additional information. The Tall City Acquisition was accounted for as an asset acquisition, as substantially all the gross assets acquired are concentrated in a group of similar identifiable assets. Based on the relative fair values on Tall City Closing Date, the acquired assets and liabilities assumed were allocated as follows: (i) $343.0 million to evaluated properties, (ii) $60.2 million to unevaluated properties, of which $4.4 million remained as of December 31, 2023, (iii) $3.4 million to operating lease right-of-use assets, (iv) $3.4 million to operating lease liabilities, (v) $1.2 million to property tax liabilities, (vi) $31.6 million to revenue suspense liabilities, (vii) $8.2 million to accrued liabilities for drilling advances and (viii) $1.8 million to asset retirement obligation liabilities.
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Table of ContentsVital Energy, Inc.
Notes to the consolidated financial statements
Maple Acquisition
On October 31, 2023 ("Maple Closing Date"), the Company purchased certain oil and gas properties in the Delaware Basin, including approximately 15,500 net acres located in Reeves County and related assets and contracts, with an effective date of September 13, 2023 (the "Maple Acquisition") from Maple Energy Holdings, LLC ("Maple").
The aggregate purchase price of $169.8 million consisted of i) 3,294,331 shares of Common Stock based upon the share price as of the Maple Closing Date, and ii) $4.9 million in transaction-related expenses. The purchase price, including shares, is inclusive of final closing adjustments. Upon entering into the purchase and sale agreement with Maple (the "Maple PSA"), the Company issued Common Stock as a deposit to be held in escrow until closing of the Maple Acquisition, of which certain shares remain in escrow post-closing to satisfy potential indemnification claims under the Maple PSA. See Note 8 for additional information. The Maple Acquisition was accounted for as an asset acquisition, as substantially all the gross assets acquired are concentrated in a group of similar identifiable assets. Based on the relative fair values on Maple Closing Date, the acquired assets and liabilities assumed were allocated as follows: (i) $145.8 million to evaluated properties, (ii) $30.6 million to unevaluated properties, all of which remained as of December 31, 2023, (iii) $3.1 million to operating lease right-of-use assets, (iv) $3.1 million to operating lease liabilities, (v) $1.3 million to property tax liabilities, (vi) $3.8 million to revenue suspense liabilities and (vii) $1.5 million to asset retirement obligation liabilities.
Forge Acquisition
On June 30, 2023 ("Forge Closing Date"), the Company purchased certain oil and natural gas properties located in the Delaware Basin, including approximately 24,000 net acres in Pecos, Reeves and Ward Counties, and related assets and contracts, with an effective date of March 1, 2023 (the "Forge Acquisition") from Forge Energy II Delaware, LLC ("Forge").
The aggregate purchase price of $397.6 million consisted of (i) $389.9 million in cash and (ii) $7.7 million in transaction-related expenses. The purchase price is inclusive of final closing adjustments. The Forge Acquisition was accounted for as an asset acquisition, as substantially all the gross assets acquired are concentrated in a group of similar identifiable assets. Based on the relative fair values on the Forge Closing Date, the acquired assets and liabilities assumed were allocated as follows: (i) $278.6 million to evaluated properties, (ii) $125.5 million to unevaluated properties, of which $50.6 million remained as of December 31, 2023, (iii) $8.9 million to equipment inventory, (iv) $13.7 million to revenue suspense liabilities and (v) $1.7 million to asset retirement obligation liabilities.
Driftwood Acquisition
On April 3, 2023 ("Driftwood Closing Date"), the Company purchased certain oil and natural gas properties in the Midland Basin, including approximately 11,200 net acres located in Upton and Reagan Counties and related assets and contracts, inclusive of derivatives (the "Driftwood Assets") with an effective date of January 1, 2023 (the "Driftwood Acquisition") from Driftwood Energy Operating, LLC ("Driftwood").
The aggregate purchase price of $201.7 million consisted of (i) $117.4 million of cash, (ii) 1,578,948 shares of Common Stock based upon the share price as of the Driftwood Closing Date and (iii) $4.2 million in transaction-related expenses. The purchase price is inclusive of final closing adjustments. The Driftwood Acquisition was accounted for as an asset acquisition, as substantially all the gross assets acquired are concentrated in a group of similar identifiable assets. Based on the relative fair values on the Driftwood Closing Date, the acquired assets and liabilities assumed were allocated as follows: (i) $207.1 million to evaluated properties, (ii) $0.5 million to revenue suspense liabilities, (iii) $4.2 million to derivative liabilities and (iv) $0.7 million to asset retirement obligation liabilities.
During the second quarter of 2023, the Company acquired additional interests in producing properties associated with the Driftwood Assets through additional sellers that exercised their "tag-along" sales rights, for total cash consideration of $8.6 million, excluding customary purchase price adjustments.

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Table of ContentsVital Energy, Inc.
Notes to the consolidated financial statements
2022 divestiture
On August 16, 2022, the Company entered into a purchase and sale agreement with Northern Oil and Gas, Inc. ("NOG"), pursuant to which the Company agreed to sell to NOG the Company’s working interests in certain specified non-operated oil and gas properties (the "NOG Working Interest Sale").
On October 3, 2022, the Company closed the NOG Working Interest Sale for an aggregate sales price of $106.1 million, inclusive of customary closing adjustments, subject to post-closing adjustments.
Exchange of unevaluated oil and natural gas properties
From time to time, the Company exchanges undeveloped acreage with third parties. The exchanges are recorded at fair value and the difference is accounted for as an adjustment of capitalized costs with no gain or loss recognized pursuant to the rules governing full cost accounting, unless such adjustment would significantly alter the relationship between capitalized costs and proved reserves of oil, NGL and natural gas.
Note 5
Leases
Lease costs
The following table presents components of total lease costs, net for the periods presented:
Years ended December 31,
(in thousands)20242023
Operating lease costs(1)
$95,719 $71,706 
Short-term lease costs(2)
149,819 56,685 
Variable lease costs(3)
10,212 97,383 
Sublease income(552)(1,198)
Total lease costs, net$255,198 $224,576 
_____________________________________________________________________________
(1)Amounts represent straight-line costs associated with the Company's operating lease right-of-use assets.
(2)Amounts include costs associated with the Company's short-term leases that are not included in the calculation of lease liabilities and right-of-use assets and, therefore, are not recorded on the consolidated balance sheets as such.
(3)Amounts are primarily comprised of the non-lease service component of drilling rig and completions commitments above the minimum required payments, and are not included in the calculation of lease liabilities and right-of-use assets. Both the minimum required payments and the non-lease service component of the drilling rig and completions commitments are capitalized as additions to oil and natural gas properties.
Operating leases
Supplemental cash flow information
The following table presents cash paid for amounts included in the measurement of operating lease liabilities, which may not agree to operating lease costs due to timing of cash payments and incurred capital expenditures for the periods presented:
Years ended December 31,
(in thousands)20242023
Operating cash outflows from operating leases$22,133 $4,595 
Investing cash outflows from operating leases(1)
$75,607 $65,305 
_____________________________________________________________________________
(1)    Amounts associated with drilling and completions operations are capitalized as additions to oil and natural gas properties.

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Table of ContentsVital Energy, Inc.
Notes to the consolidated financial statements
Lease terms and discount rates
The following table presents the weighted-average remaining lease term and weighted-average discount rate for operating leases as of the dates presented:
December 31, 2024December 31, 2023
Weighted-average remaining lease term2.18 years2.54 years
Weighted-average discount rate7.89 %8.26 %
Maturities
The following table reconciles the undiscounted cash flows for recognized operating lease liabilities for each of the first five years and the total remaining years to the operating lease liabilities recorded on the consolidated balance sheet as of the date presented:
(in thousands)December 31, 2024
2025$78,176 
202614,081 
20274,622 
20282,986 
20292,730 
Thereafter8,579 
Total minimum lease payments111,174 
Less: imputed interest(11,298)
Present value of future minimum lease payments$99,876 
Other information
See Note 2 for disclosure of supplemental non-cash adjustments information related to operating leases.
Note 6
Property and equipment
Oil and natural gas properties
The following table presents capitalized employee-related incurred capital expenditures in the acquisition, exploration and development of oil and natural gas properties for the periods presented:
Years ended December 31,
(in thousands)202420232022
Capitalized employee-related costs$20,815 $22,179 $17,026 
See Unaudited Supplementary Information included elsewhere in this Annual Report for total incurred capital expenditures in the acquisition, exploration and development of oil and natural gas properties, which includes the aforementioned capitalized employee-related costs.
The following table presents depletion expense, which is included in "Depletion, depreciation and amortization" on the consolidated statements of operations, and depletion expense per BOE sold of evaluated oil and natural gas properties for the periods presented:
Years ended December 31,
(in thousands except per BOE data)202420232022
Depletion expense of evaluated oil and natural gas properties$720,190 $446,611 $298,259 
Depletion expense per BOE sold$14.70 $12.67 $9.92 
The full cost ceiling is based principally on the estimated future net cash flows from proved oil, NGL and natural gas reserves, which exclude the effect of the Company's commodity derivative transactions, discounted at 10%. SEC guidelines require companies to use the unweighted arithmetic average first-day-of-the-month price for each month within the 12-month period
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Table of ContentsVital Energy, Inc.
Notes to the consolidated financial statements
prior to the end of the reporting period before differentials ("Benchmark Prices"). The Benchmark Prices are then adjusted for quality, certain transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the delivery point ("Realized Prices") without giving effect to the Company's commodity derivative transactions. The Realized Prices are utilized to calculate the estimated future net cash flows in the full cost ceiling calculation. Additional significant inputs included in the calculation of discounted cash flows used in the impairment analysis include the Company's estimate of operating and development costs, anticipated production of proved reserves and other relevant data. In the event the unamortized cost of evaluated oil and natural gas properties being depleted exceeds the full cost ceiling, as defined by the SEC, the excess is expensed in the period such excess occurs. Once incurred, a write-down of oil and natural gas properties is not reversible.
The unamortized cost of evaluated oil and natural gas properties being depleted exceeded the full cost ceiling during the quarterly period ended December 31, 2024. Accordingly, the Company recorded a $481.3 million full cost ceiling impairment, which is included in "Impairment expense" on the consolidated statements of operations for the year ended December 31, 2024. The unamortized cost of evaluated oil and natural gas properties being depleted did not exceed the full cost ceiling during 2023 and 2022 and, as such, no full cost ceiling impairments were recorded for the years ended December 31, 2023 and 2022.
The following table presents the Benchmark Prices and the Realized Prices as of the dates presented:
December 31, 2024December 31, 2023December 31, 2022
Benchmark Prices:
Oil ($/Bbl)$75.48 $78.22 $90.15 
NGL ($/Bbl)(1)(2)
$75.48 $78.22 $41.77 
Natural gas ($/MMBtu)$2.13 $2.64 $5.20 
Realized Prices:
Oil ($/Bbl)$76.76 $79.52 $96.21 
NGL ($/Bbl)$13.66 $16.46 $29.84 
Natural gas ($/Mcf)$0.85 $1.17 $4.24 
_____________________________________________________________________________
(1)    Based on the Company's average composite NGL barrel.
(2)    During 2023, the Company began utilizing WTI NYMEX in the calculation of its NGL Benchmark Prices.
Midstream and other fixed assets
Midstream assets consist of oil and natural gas pipeline gathering assets, related equipment, oil delivery stations, water storage and treatment facilities and their related asset retirement cost. Midstream and other fixed assets are recorded at cost, net of any impairment, and are subject to depreciation and amortization. Land is recorded at cost and is not subject to depreciation. Depreciation of assets is recorded using the straight-line method based on estimated useful lives of 3 to 20 years, as applicable. Leasehold improvements are capitalized and amortized over the shorter of the estimated useful lives of the assets or the terms of the related leases. Expenditures for significant betterments or renewals, which extend the useful lives of existing fixed assets, are capitalized and depreciated. Upon retirement or disposition, the cost and related accumulated depreciation are removed from the accounts and any gain or loss is recognized in "Gain (loss) on disposal of assets, net" in the consolidated statements of operations.

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Notes to the consolidated financial statements
Midstream and other fixed assets consisted of the following components as of the dates presented:
(in thousands)December 31, 2024December 31, 2023
Midstream service assets$169,984 $158,749 
Computer hardware and software38,644 29,007 
Vehicles3,210 5,046 
Leasehold improvements7,155 7,136 
Buildings7,637 7,039 
Other7,690 7,710 
Depreciable total234,320 214,687 
Less accumulated depreciation, amortization and impairment(121,876)(107,541)
Depreciable total, net$112,444 $107,146 
Land21,821 23,147 
Total midstream and other fixed assets, net$134,265 $130,293 
Note 7
Debt
Long-term debt, net
The following table presents the Company's long-term debt and unamortized debt issuance costs, discounts and premiums included in "Long-term debt, net" on the consolidated balance sheets as of the dates presented:
(in thousands)December 31, 2024December 31, 2023
10.125% senior unsecured notes due 2028 (January 2028 Notes)
$— $700,309 
7.750% senior unsecured notes due 2029 (July 2029 Notes)
298,214 298,214 
9.750% senior unsecured notes due 2030 (September 2030 Notes)
302,364 500,000 
7.875% senior unsecured notes due 2032 (March 2032 Notes)
1,000,000 — 
Senior Secured Credit Facility880,000 135,000 
Total long-term debt$2,480,578 $1,633,523 
Unamortized debt issuance costs(1)
(24,579)(21,800)
Unamortized discounts(3,132)(6,068)
Unamortized premiums1,375 3,769 
Total long-term debt, net$2,454,242 $1,609,424 
_____________________________________________________________________________
(1)Unamortized debt issuance costs related to the Senior Secured Credit Facility of $12.5 million and $14.1 million as of December 31, 2024 and 2023, respectively, are included in "Other noncurrent assets, net" on the consolidated balance sheets.
Senior Secured Credit Facility
On May 8, 2024, the Company entered into the Twelfth Amendment to the Senior Secured Credit Facility (the "Twelfth Amendment"). The Twelfth Amendment, among other things, reaffirmed the borrowing base at $1.5 billion and (ii) increased the aggregate elected commitment to $1.35 billion under the Senior Secured Credit Facility.
On September 20, 2024, in connection with the closing of the Point Acquisition, the Company entered into the Thirteenth Amendment to the Senior Secured Credit Facility (the "Thirteenth Amendment"). The Thirteenth Amendment, among other things, increased the aggregate elected commitment to $1.5 billion under the Senior Secured Credit Facility. See Note 4 for additional discussion of the Point Acquisition.
As of December 31, 2024, the Senior Secured Credit Facility, which matures on September 13, 2027, had a maximum credit amount of $3.0 billion, a borrowing base and an aggregate elected commitment of $1.5 billion, and an outstanding balance of $880.0 million subject to a weighted-average interest rate of 7.240%. The borrowing base is subject to a semi-annual redetermination occurring by May 1 and November 1 of each year based on the lenders' evaluation of the Company's oil, NGL
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Table of ContentsVital Energy, Inc.
Notes to the consolidated financial statements
and natural gas reserves. As defined in the Senior Secured Credit Facility, (i) the Adjusted Base Rate advances under the facility bear interest payable quarterly at an Adjusted Base Rate plus applicable margin, which ranges from 1.25% to 2.25%, based on the ratio of outstanding revolving credit to the borrowing base under the Senior Secured Credit Facility; and (ii) the SOFR advances under the facility bear interest, at the Company's election, at the end of one-month, three-month or six-month interest periods (and in the case of six-month interest periods, every three months prior to the end of such interest period) at a Secured Overnight Financing Rate ("SOFR") plus an applicable margin, which ranges from 2.25% to 3.25%, based on the ratio of outstanding revolving credit to the borrowing base under the Senior Secured Credit Facility. Vital Energy is required to pay a quarterly commitment fee on the unused portion of the financial institutions' commitment, which ranges from 0.375% of 0.500%.
The Senior Secured Credit Facility is secured by a first-priority lien on the assets and stock of Vital Energy and Vital Midstream Services, LLC ("VMS") (the "Guarantor"), including oil and natural gas properties constituting at least 85% of the present value of the Company's proved reserves. Further, the Company is subject to various financial and non-financial covenants on a consolidated basis, including a current ratio at the end of each calendar quarter, of not less than 1.00 to 1.00. As defined by the Senior Secured Credit Facility, the current ratio represents the ratio of current assets to current liabilities, inclusive of available capacity and exclusive of current balances associated with derivative positions. Additionally, the Company must maintain as of the last day of each calendar quarter a ratio of (a) its total debt (excluding reimbursement obligations in respect of undrawn letters of credit, if no loans are outstanding under the Senior Secured Credit Facility) minus a maximum of $100.0 million of unrestricted and unencumbered cash and cash equivalents, to (b) "Consolidated EBITDAX," as defined in the Senior Secured Credit Facility, for any period of four consecutive calendar quarters ending on the last day of such applicable calendar quarter of not greater than 3.50 to 1.00. The Company was in compliance with these covenants as of December 31, 2024 and 2023, as then in effect.
Additionally, the Senior Secured Credit Facility provides for the issuance of letters of credit, limited to the lesser of total capacity or $80.0 million. As of December 31, 2024 and 2023, the Company had no letters of credit outstanding under the Senior Secured Credit Facility. See Note 18 for discussion of additional borrowings and repayments on the Senior Secured Credit Facility subsequent to December 31, 2024.
Senior unsecured notes
March 2032 Notes
On March 28, 2024, the Company completed an offering of $800.0 million in aggregate principal amount of 7.875% senior unsecured notes due 2032 (the "Initial March 2032 Notes") for net proceeds of $784.8 million. The net proceeds from this offering and the Tack-On March 2032 Notes (defined below) were used to (i) extinguish in full the Company's outstanding January 2028 Notes (defined below), (ii) reduce the outstanding principal amount of the September 2030 Notes (defined below) and (iii) repay a portion of the outstanding borrowings on the Senior Secured Credit Facility. On March 29, 2024, the Company settled a cash tender offer on the January 2028 Notes for an aggregate principal amount outstanding of $431.2 million.
On April 3, 2024, the Company completed an offering of an additional $200.0 million in aggregate principal amount of 7.875% senior unsecured notes due 2032 (the "Tack-On March 2032 Notes," and, together with the Initial March 2032 Notes, the "March 2032 Notes"), at 100.750% of par, under the same indenture dated as of March 28, 2024 for net proceeds of approximately $198.7 million. On April 3, 2024, the Company settled a cash tender offer on the September 2030 Notes of $197.6 million and on April 29, 2024, the Company redeemed the remaining principal amount outstanding on the January 2028 Notes of $269.2 million at a redemption price of 105.063%.
September 2030 Notes
On September 25, 2023, the Company completed an offering and sale of $500.0 million in aggregate principal amount of 9.750% senior unsecured notes due 2030 (the "September 2030 Notes"). Interest for the September 2030 Notes is payable semi-annually, in cash in arrears on April 15 and October 15 of each year, commencing October 15, 2023 with interest from closing to that date. The September 2030 Notes were issued at 98.742% of par value, which resulted in a discount upon issuance of $6.3 million.
The Company received net proceeds of approximately $484.7 million from the September 2030 Notes, after deducting issuance discounts, underwriting discounts and commissions and offering costs. The proceeds from the offering were used to
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Table of ContentsVital Energy, Inc.
Notes to the consolidated financial statements
redeem the entire principal amount outstanding of its January 2025 Notes and for general corporate purposes, including repaying a portion of the borrowings outstanding under the Company's Senior Secured Credit Facility.
July 2029 Notes
On July 16, 2021, the Company completed a private offering and sale of $400.0 million in aggregate principal amount of 7.750% senior unsecured notes due 2029 (the "July 2029 Notes"). Interest for the July 2029 Notes is payable semi-annually, in cash in arrears on January 31 and July 31 of each year, commencing January 31, 2022 with interest from closing to that date.
The Company received net proceeds of approximately $392.0 million from the July 2029 Notes, after deducting underwriting discounts and commissions and estimated offering expenses. The proceeds from the offering were used for general corporate purposes, including repaying a portion of the borrowings outstanding under the Senior Secured Credit Facility.
January 2025 Notes and January 2028 Notes
On January 24, 2020, the Company completed an offer and sale (the "Offering") of $600.0 million in aggregate principal amount of 9.500% senior unsecured notes due 2025 (the "January 2025 Notes") and $400.0 million in aggregate principal amount of 10.125% senior unsecured notes due 2028 (the "Original January 2028 Notes"). Interest for both the January 2025 Notes and Original January 2028 Notes is payable semi-annually, in cash in arrears on January 15 and July 15 of each year.
The Company received net proceeds of $982.0 million from the Offering, after deducting underwriting discounts and commissions and estimated offering expenses. The proceeds from the Offering were used (i) to fund cash tender offers and consent solicitations for any or all of the Company's outstanding 5 5/8% senior unsecured notes due 2022 and 6 1/4% senior unsecured notes due 2023 (ii) to repay the Company's 5 5/8% senior unsecured notes due 2022 and 6 1/4% senior unsecured notes due 2023 that remained outstanding after settling the Tender Offers and (iii) for general corporate purposes, including repayment of a portion of the borrowings outstanding under the Company's Senior Secured Credit Facility.
On September 25, 2023, the Company completed an offering and sale of $400.0 million in aggregate principal amount of new 10.125% senior unsecured notes due 2028 (the "New January 2028 Notes" and, together with the Original January 2028 Notes, the "January 2028 Notes") as additional notes under, and subject to the terms of, the indenture governing the January 2028 Notes. The New January 2028 Notes were issued at 101.000% of par value, which resulted in a premium upon issuance of $4.0 million. The Company received net proceeds of approximately $396.7 million from the New January 2028 Notes, after issuance premiums and deducting underwriting discounts and commissions and offering costs.
On December 27, 2023, the Company issued a notice to redeem the entire $455.6 million principal amount outstanding of its January 2025 Notes using the proceeds from the offering of the September 2030 Notes and New January 2028 Notes. As a result, the Company incurred a $2.2 million charge related to the early redemption and a write-off of debt issuance costs of $1.5 million, both of which are included in "Loss on extinguishment of debt, net" on the consolidated statements of operation for the year ended December 31, 2023. On December 27, 2023, the Company was legally released as the obligor of the January 2025 Notes by establishing and funding an irrevocable trust to redeem the January 2025 Notes. As a result, the transferred assets and long-term debt were derecognized from the balance sheet as of the funding date of the irrevocable trust. On January 15, 2024, the January 2025 Notes were redeemed using the funds irrevocably deposited in trust with the trustee on December 27, 2023.
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Table of ContentsVital Energy, Inc.
Notes to the consolidated financial statements
Tender offers and repurchases
The following table presents the components of the Company's loss on extinguishment of debt during the periods presented:
Years ended December 31,
(in thousands)20242023
2022(1)
January 2025 Notes$— $455,628 $122,285 
January 2028 Notes700,309 — 60,735 
July 2029 Notes— — 101,786 
September 2030 Notes197,636 — — 
Total principal amount tendered or redeemed897,945 455,628 284,806 
Extinguishment of debt(2)
(952,214)(457,792)(282,902)
Early tender or redemption discount (premium) and other related charges(54,269)(2,164)1,904 
Write-off of debt issuance costs(13,121)(1,875)(3,363)
Write-off of issuance discount(2,311)— — 
Write-off of issuance premium3,586 — — 
Loss on extinguishment of debt, net(3)
$(66,115)$(4,039)$(1,459)
______________________________________________________________________________
(1)Amounts presented for the year ended December 31, 2022 represent the Company's repurchases of its senior unsecured notes under authorized bond purchase programs. No senior unsecured notes were repurchased under an authorized bond purchase program during the years ended December 31, 2024 and 2023.
(2)Amounts are included in "Extinguishment of debt" in cash flows from financing activities on the consolidated statements of cash flows.
(3)Amounts are included in "Loss on extinguishment of debt, net" on the consolidated statements of operations.
Covenants
The terms of each of the Company's senior unsecured notes include covenants, which are in addition to but different than similar covenants in the Senior Secured Credit Facility, which limit the Company's ability to incur indebtedness, make restricted payments, grant liens and dispose of assets. The Company was in compliance with these covenants as of December 31, 2024 and 2023.
Each of the Company's senior unsecured notes are fully and unconditionally guaranteed on a senior unsecured basis by Vital Midstream Services, LLC and certain of the Company's future restricted subsidiaries, subject to certain automatic customary releases, including the sale, disposition or transfer of all of the capital stock or of all or substantially all of the assets of a subsidiary guarantor to one or more persons that are not the Company or a restricted subsidiary, exercise of legal defeasance or covenant defeasance options or satisfaction and discharge of the applicable indenture, designation of a subsidiary guarantor as a non-guarantor restricted subsidiary or as an unrestricted subsidiary in accordance with the applicable indenture, release from guarantee under the Senior Secured Credit Facility, or liquidation or dissolution.
Interest expense
The following table presents amounts that have been incurred and charged to interest expense:
Years ended December 31,
(in thousands)202420232022
Interest expense on borrowings$171,047 $144,731 $123,255 
Amortization of debt issuance costs and other adjustments8,160 7,980 5,738 
Less capitalized interest(1,413)(2,892)(3,872)
Total interest expense$177,794 $149,819 $125,121 
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Notes to the consolidated financial statements
Note 8
Stockholders' equity
Equity offering
On September 19, 2023, the Company completed the sale of 2,750,000 shares of its common stock for net proceeds of $140.2 million, after underwriting discounts, commissions and offering expenses. On September 29, 2023, the underwriters exercised their option to purchase an additional 412,500 shares of common stock, which resulted in net proceeds to the Company of $21.0 million, after underwriting discounts, commissions and offering expenses.
Equity issued for acquisitions of oil and natural gas properties
During the years ended December 31, 2024 and 2023, the Company issued shares of its common stock and Preferred Stock in connection with the closing of various acquisitions of oil and gas properties, as shown in the table below.
AcquisitionClosing dateCommon stock issuedPreferred stock issued
PEP(1)
2/2/2024878,690 980,272 
Grey Rock(1)
12/21/2023627,026 595,104 
Tall City(2)
11/6/20231,402,258  N/A
Henry(3)
11/5/20232,145,725 6,131,381 
Maple(4)
10/31/20233,370,497 N/A
Driftwood4/3/20231,578,948 N/A
_____________________________________________________________________________
(1)On May 23, 2024, the Preferred Stock issued in connection with the PEP Acquisition and Grey Rock Acquisition were converted to common shares. See "Preferred Stock" below for additional discussion.
(2)As of December 31, 2023, 773,290 of the common shares issued for the Tall City Acquisition were in escrow pending post-close settlements. During the year ended December 31, 2024, 396,570 of the Tall City escrow shares were released to the seller, leaving 376,720 Tall City shares in escrow as of December 31, 2024.
(3)On November 29, 2023, the Preferred Stock issued in connection with the Henry Acquisition were converted to common shares. See "Preferred Stock" below for additional discussion.
(4)As of December 31, 2023, 357,500 of the common shares issued for the Maple Acquisition were in escrow pending post-close settlements. During the year ended December 31, 2024, 79,998 of the Maple escrow shares were returned to the Company and retired and 262,969 shares were released to the seller, leaving 14,533 of the Maple shares in escrow as of December 31, 2024.
See Note 4 for additional information on the Company's acquisitions.
Preferred Stock
The Company's non-voting Preferred Stock was entitled to cumulative preferred cash dividends at an initial rate of 2.0% per annum of the liquidation preference per share of $54.96, as defined in the Certificate of Designations, provided that such rate shall automatically increase to (i) 5.0% on September 15, 2024, and (ii) 8.0% on September 15, 2025, payable quarterly in arrears, if, and when, declared. If the Company fails to pay in full any distribution on the Preferred Stock, the amount of such unpaid distribution will accrue and accumulate from the last day of the quarter for which such distribution is due until paid in full. The Company may, at any time and from time to time, elect to redeem all outstanding shares of Preferred Stock, in accordance with the terms of the Certificate of Designations. Upon stockholder approval, the Preferred Stock is to be converted to an equal number of shares of common stock.
On November 21, 2023, upon recommendation of the Company's board of directors, stockholders approved the conversion of the 6,131,381 shares of Preferred Stock issued in connection with the Henry Acquisition to an equal number of shares of common stock. The conversion occurred on November 29, 2023. As a result of the conversion, the Company paid a dividend of $0.4 million for the period for which the Preferred Stock was outstanding. On May 23, 2024, upon recommendation of the Company's board of directors, stockholders approved the conversion of the remaining 1,575,376 outstanding shares of Preferred Stock issued in connection with the PEP and Grey Rock Acquisitions to an equal number of shares of common stock. The conversion occurred on June 4, 2024. As a result of the conversion, the Company paid a dividend of $0.3 million for the period the Preferred Stock was outstanding during the second quarter of 2024.
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Notes to the consolidated financial statements
Share repurchase program
On May 31, 2022, the Company's board of directors authorized a $200.0 million share repurchase program. The repurchase program commenced in May 2022 and was originally set to expire in May 2024. On May 23, 2024, the board of directors approved an amendment to the share repurchase program to (i) increase the shares of Common Stock which the Company may purchase to a total aggregate authorization of $237.3 million, and (ii) extend the expiration date to May 22, 2026. Share repurchases under the program may be made through a variety of methods, which may include open market purchases, including under plans complying with Rule 10b5-1 of the Exchange Act, and privately negotiated transactions. The timing and actual number of share repurchases will depend upon several factors, including market conditions, business conditions, the trading price of the Company's common stock and the nature of other investment opportunities available to the Company. The following table presents the Company's open market repurchases of its common stock during the periods presented:
(in thousands, except for share and share price data)Year ended
December 31, 2022
Shares of Company common stock repurchased490,536
Average share price(1)
$76.02 
Total$37,290 
______________________________________________________________________________
(1)Average share price includes any commissions paid to repurchase stock.
All shares were retired upon repurchase. No shares were repurchased during the years ended December 31, 2024 and 2023.
Note 9
Compensation plans
Equity Incentive Plan
The Equity Incentive Plan provides for the granting of incentive awards in the form of restricted stock awards, stock option awards, performance share unit awards, restricted stock unit awards, stock appreciation rights, stock bonus awards and other awards. On May 23, 2024, the Company's stockholders approved an amendment and restatement to the Equity Incentive Plan, which increased the maximum number of shares of the Company's common stock issuable under the Equity Incentive Plan from 2,432,500 to 3,332,500 shares.
As of December 31, 2024, the Company had outstanding restricted stock awards and performance share unit awards.
Equity Awards
Restricted stock awards and restricted stock unit awards
All service vesting restricted stock awards are treated as issued and outstanding in the consolidated financial statements. If the termination of employment is by reason of death or disability, all of the holder's restricted stock will automatically vest. Restricted stock awards granted to employees vest in a variety of schedules that mainly include (i) 33%, 33% and 34% vesting per year beginning on the first anniversary of the grant date and (ii) full vesting on the third anniversary of the grant date. Non-employee directors are granted restricted stock unit awards which are 100% vested on the date of grant, with the option to defer settlement of some or all of such awards in shares until the director's separation from service if the director timely elects in accordance with the terms of the Nonqualified Director Deferred Compensation Plan.
Share-settled performance share unit awards
Share-settled performance share unit awards, which the Company has determined are equity awards, are subject to a combination of market, performance and service vesting criteria. For portions of awards with market criteria, a Monte Carlo simulation prepared by an independent third party is utilized to determine the grant-date (or modification date) fair value, and the associated expense is recognized on a straight-line basis over the three-year requisite service period of the awards. For portions of awards with performance criteria, the fair value is equal to the Company's closing stock price on the grant date (or modification date), and for each reporting period, the associated expense fluctuates and is adjusted based on an estimated payout of the number of shares of common stock to be delivered on the payment date for the three-year performance period, which begins either at the start of the calendar year in which the award is granted or on December 1 of the year prior to the Calendar year in which the award is granted.
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Notes to the consolidated financial statements
For share-settled performance share unit awards granted in 2022, the market criteria consists of: (i) annual relative stockholder return comparing the Company's stockholder return to the stockholder return of the exploration and production companies listed in the Russell 2000 index and (ii) annual absolute total stockholder return, together the "PSU Matrix." The performance criteria for these awards consists of: (i) earnings before interest, taxes, depreciation, amortization and exploration expense ("EBITDAX") and three-year total debt reduction (the "EBITDAX/Total Debt Component") (ii) growth in inventory (the "Inventory Growth Component") and (iii) emissions reduction (the "ESG Component"). Any units earned are expected to be paid in shares in the first quarter following the completion of the respective requisite service periods based on the achievement of certain market and performance criteria, and the payout range was 0% to 225%. The awards granted February 22, 2022 had a performance period of January 1, 2022 to December 31, 2024. Certain of the market and performance criteria were satisfied, resulting in a 82% payout, which will be paid in shares during the first quarter of 2025.
Equity award activity
The following table presents activity for equity compensation awards for the year ended December 31, 2024:
(in thousands, except per share data)Restricted stock awardsWeighted-average grant-date fair value
(per share)		Share-settled performance share unit awards
Weighted-average grant-date fair value
(per share)(2)
Outstanding as of December 31, 2023
472 $56.8748 $89.76
Granted484 $45.16— 
Forfeited(51)$51.81— 
Vested(1)
(240)$52.06— 
Outstanding as of December 31, 2024
665 $50.4748 $89.76
_____________________________________________________________________________
(1)The aggregate intrinsic value of vested restricted stock awards for the year ended December 31, 2024 was $10.9 million.
(2)The weighted-average grant-date fair value of share-settled performance share unit awards assumes 100%, or target level, achievement of the performance criteria.
As of December 31, 2024, total unrecognized cost related to equity compensation awards was $19.3 million, which will be settled in shares. Such cost will be recognized on a straight-line basis over an expected weighted-average period of 1.57 years.
Equity-based liability awards
Cash-settled performance share unit awards
Cash-settled performance share unit awards, which the Company has determined are liability awards since they are settled in cash, are subject to a combination of market, performance and service vesting criteria. For portions of awards with market criteria, a Monte Carlo simulation prepared by an independent third party is utilized to determine the fair value, and is re-measured at each reporting period until settlement. For portions of awards with performance criteria, the Company's closing stock price is utilized to determine the fair value and is re-measured on the last trading day of each reporting period until settlement and, additionally, the associated expense fluctuates based on an estimated payout for the three-year performance period. The expense related to the cash-settled performance share unit awards is recognized on a straight-line basis over the three-year requisite service period of the awards, and the life-to-date recognized expense is adjusted accordingly at each reporting period based on the quarterly fair value re-measurements and redetermination of the estimated payout for the performance criteria. For each award, the three-year performance period begins at the start of the calendar year in which the award is granted.
For cash-settled performance share unit awards granted in 2024, the market criteria consists of the PSU Matrix. The performance criteria for these awards consists of: (i) the EBITDAX/Total Debt Component, (ii) the Inventory Growth Component and (iii) the ESG Component. Any units earned are expected to be paid in cash during the first quarter following the completion of the requisite service period, based on the achievement of certain market and performance criteria, and the payout can range from 0% to 250% for the market criteria and 0% to 200% for the performance criteria.
For cash-settled performance share unit awards granted in 2023, the market criteria consists of the PSU Matrix. The performance criteria for these awards consists of: (i) the EBITDAX/Total Debt Component, (ii) the Inventory Growth
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Notes to the consolidated financial statements
Component and (iii) the ESG Component. Any units earned are expected to be paid in cash during the first quarter following the completion of the requisite service period, based on the achievement of certain market and performance criteria, and the payout can range from 0% to 250% for the market criteria and 0% to 200% for the performance criteria.
For cash-settled performance share unit awards granted in 2021, the market criteria consists of the PSU Matrix. The performance criteria for these awards consists of: (i) the EBITDAX/Total Debt Component and (ii) the Inventory Growth Component. Potential payout of these awards ranged from 0% to 250% for the market criteria and 0% to 200% for the performance criteria. In the first quarter of 2024, following the completion of the requisite service period and achievement of certain market and performance criteria, the granted awards were issued at a 145.83% payout.
Phantom unit awards
Phantom unit awards, which the Company has determined are liability awards, represent the holder's right to receive the cash equivalent of one share of common stock of the Company for each phantom unit as of the applicable vesting date, subject to withholding requirements. Phantom unit awards granted to employees vest 33%, 33% and 34% per year beginning on the first anniversary of the grant date.
Equity-based liability award activity
The following table presents activity for equity-based liability awards for the year ended December 31, 2024:
(in thousands)Cash-settled performance share
unit awards		Phantom
unit awards
Outstanding as of December 31, 2023
158 2 
Granted141 — 
Forfeited(1)— 
Vested(1)(2)
(83)(2)
Outstanding as of December 31, 2024
215 — 
_____________________________________________________________________________
(1)The cash-settled performance share unit awards granted on March 9, 2021 had a performance period of January 1, 2021 to December 31, 2023 and, as their market and performance criteria were satisfied, resulted in a 145.83% payout, or 120,297 units. As such, the granted awards vested and were paid out in cash on March 8, 2024 at $50.38 per unit based on the Company's closing stock price on the vesting date.
(2)On March 1, 2024, the vested phantom unit awards were settled and paid out in cash at a fair value of $50.81 based on the Company's closing stock price on the vesting date.
As of December 31, 2024, total unrecognized cost related to equity-based liability awards was $3.2 million, which will be settled in cash. Such cost will be recognized on a straight-line basis over an expected weighted-average period of 1.78 years.
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Notes to the consolidated financial statements
Fair value assumptions
The Company utilizes the closing stock price on the grant date to determine the fair value of restricted stock awards.
The following table presents (i) the assumptions used to estimate the fair values per performance share unit and (ii) the expense per performance share unit, which is the fair value per performance share unit adjusted for the estimated payout of the performance criteria, for the outstanding performance share unit awards as of December 31, 2024 for the grant dates presented:
Share-settled performance share unit awardsCash-settled performance share unit awardsCash-settled performance share unit awards
February 22, 2022February 15, 2023February 20, 2024
Remaining performance period on grant date2.86 yearsN/AN/A
Remaining performance periodN/A1 year2 years
Risk-free interest rate(1)
1.71 %4.17 %4.21 %
Dividend yield— %— %— %
Expected volatility(2)
119.25 %41.59 %45.82 %
Expense per performance share unit as of December 31, 2024
$108.52$24.60$25.36
______________________________________________________________________________
(1)The remaining performance period matched zero-coupon risk-free interest rate was derived from the U.S. Treasury constant maturities yield curve on the grant date for each respective award.
(2)The Company utilized its own remaining performance period matched historical volatility in order to develop the expected volatility.
Equity-based compensation
The following table reflects equity-based compensation expense for the years presented:
Years ended December 31,
(in thousands)202420232022
Equity awards:
Restricted stock awards$16,364 $12,114 $8,596 
Share-settled performance share unit awards1,972 1,855 1,590 
Total share-settled equity-based compensation, gross$18,336 $13,969 $10,186 
Less amounts capitalized (3,690)(2,975)(1,783)
Total share-settled equity-based compensation, net$14,646 $10,994 $8,403 
Liability awards:
Cash-settled performance share unit awards$2,116 $2,932 $741 
Phantom unit awards20 270 1,186 
Total cash-settled equity-based compensation, gross$2,136 $3,202 $1,927 
Less amounts capitalized(18)(50)(272)
Total cash-settled equity-based compensation, net$2,118 $3,152 $1,655 
Total equity-based compensation, net$16,764 $14,146 $10,058 
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Table of ContentsVital Energy, Inc.
Notes to the consolidated financial statements
Note 10
Net income (loss) per common share
Basic net income (loss) per common share is computed by first subtracting preferred stock dividends from net income (loss) to arrive at net income (loss) available to common stockholders, and then dividing net income (loss) available to common stockholders by the basic weighted-average common shares outstanding for the period. Diluted net income (loss) per common share is computed by dividing net income (loss) by the diluted weighted-average common shares outstanding for the period, which reflects the potential dilution of preferred stock and non-vested equity-based compensation awards. See Notes 8 and 9 for additional discussion of the Company's preferred stock and equity-based compensation awards. For the year ended December 31, 2024, all these awards were anti-dilutive due to the Company's net loss and, therefore, were excluded from the calculation of diluted net loss per common share.
The following table reflects the calculations of basic and diluted (i) weighted-average common shares outstanding and (ii) net income (loss) per common share for the periods presented:
Years ended December 31,
(in thousands, except for per share data)202420232022
Net income (loss) $(173,521)$695,078 $631,512 
Less: Preferred stock dividends(652)(449)— 
Net income (loss) available to common stockholders$(174,173)$694,629 $631,512 
Weighted-average common shares outstanding:
Basic36,725 20,254 16,672 
Dilutive non-vested restricted stock awards— 106 183 
Dilutive non-vested share-settled performance share unit awards— 2 12 
Dilutive preferred stock— 421 — 
Diluted36,725 20,783 16,867 
Net income (loss) per common share:
Basic$(4.74)$34.30 $37.88 
Diluted$(4.74)$33.44 $37.44 
Anti-dilutive weighted-average common shares outstanding(1):
Non-vested restricted stock awards221 254 7 
Non-vested share-settled performance share unit awards16 — 19 
Preferred stock581 — — 
_____________________________________________________________________________
(1)Shares excluded from the diluted net income (loss) per common share calculation because their effect would be anti-dilutive.
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Table of ContentsVital Energy, Inc.
Notes to the consolidated financial statements
Note 11
Derivatives
The Company has two types of derivative instruments as of December 31, 2024: (i) commodity derivatives and (ii) a contingent consideration derivative. See (i) Note 2 for the Company's significant accounting policies for derivatives and presentation in the consolidated financial statements, (ii) Note 12 for fair value measurement of derivatives on a recurring basis and (iii) Note 18 for derivatives subsequent events.
The following table summarizes components the Company's gain (loss) on derivatives, net by type of derivative instrument for the periods presented:
Years ended December 31,
(in thousands)202420232022
Commodity$52,931 $89,951 $(291,959)
Contingent consideration(14,791)6,279 (6,764)
Gain (loss) on derivatives, net$38,140 $96,230 $(298,723)
Commodity
Due to the inherent volatility in oil, NGL and natural gas prices and the sometimes wide pricing differentials between where the Company produces and where the Company sells such commodities, the Company engages in commodity derivative transactions, such as puts, swaps, collars and basis swaps to hedge price risk associated with a portion of the Company's anticipated sales volumes. By removing a portion of the price volatility associated with future sales volumes, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flows from operations. During the year ended December 31, 2024, the Company's derivatives were settled based on reported prices on commodity exchanges, with (i) oil derivatives settled based on WTI NYMEX, Argus WTI Midland and Argus WTI Formula Basis pricing, (ii) NGL derivatives settled based on Mont Belvieu OPIS pricing and (iii) natural gas derivatives settled based on Henry Hub NYMEX and Waha Inside FERC pricing.
The following table summarizes open commodity derivative positions as of December 31, 2024, for commodity derivatives that were entered into through December 31, 2024, for the settlement periods presented:
Year 2025Year 2026Year 2027
Oil:
WTI NYMEX - Swaps:
Volume (Bbl)16,074,000 4,005,000 — 
Weighted-average price ($/Bbl)$74.79 $71.42 $— 
Natural gas:
Waha Inside FERC - Swaps:
Volume (MMBtu)42,705,000 44,530,000 43,800,000 
Weighted-average price ($/MMBtu)$2.31 $2.43 $2.70 
Contingent consideration
On May 7, 2021, the Company entered into a purchase and sale agreement (the "Sixth Street PSA"), to sell 37.5% of the Company's working interest in certain producing wellbores and the related properties primarily located within Glasscock and Reagan Counties, Texas. The Sixth Street PSA provided for potential contingent payments to be paid to the Company if certain cash flow targets are met related to divested oil and natural gas property operations (the"Sixth Street Contingent Consideration"). The Sixth Street Contingent Consideration provides the Company with the right to receive up to a maximum of $93.7 million in additional cash consideration, comprised of potential quarterly payments through June 2027 totaling up to $38.7 million and a potential balloon payment of $55.0 million in June 2027. As of December 31, 2024, the Company had received life-to-date contingent consideration payments of $4.3 million, with maximum remaining potential cash consideration totaling $79.1 million. The fair value of the Sixth Street Contingent Consideration was determined to be $16.3 million as of December 31, 2024 and $31.1 million as of December 31, 2023.
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Notes to the consolidated financial statements
Note 12
Fair value measurements
The Company has categorized its assets and liabilities measured at fair value, based on the priority of inputs to the valuation techniques, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).
Assets and liabilities recorded at fair value on the consolidated balance sheets are categorized based on inputs to the valuation techniques as follows: 
Level 1—
Assets and liabilities recorded at fair value for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access. Active markets are considered to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2—Assets and liabilities recorded at fair value for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the assets or liabilities. Substantially all of these inputs are observable in the marketplace throughout the full term of the price risk management instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace.
Level 3—Assets and liabilities recorded at fair value for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. Unobservable inputs are not corroborated by market data. These inputs reflect management's own assumptions about the assumptions a market participant would use in pricing the asset or liability.
Fair value measurement on a recurring basis
For further discussion of the Company's derivatives, see Notes (i) 2 for the Company's significant accounting policies for derivatives, (ii) 11 for derivatives and (iii) 18 for derivatives subsequent events.
Balance sheet presentation
The following tables present the Company's derivatives by (i) balance sheet classification, (ii) derivative type and (iii) fair value hierarchy level, and provide a total, on a gross basis and a net basis reflected in "Derivatives" on the consolidated balance sheets as of the dates presented:
December 31, 2024
(in thousands)Level 1Level 2Level 3Total gross fair valueAmounts offsetNet fair value presented on the consolidated balance sheets
Assets:
Current:
Commodity$— $98,825 $— $98,825 $2,638 $101,463 
Contingent consideration— — 11 11 — 11 
Noncurrent:
Commodity— 28,126 — 28,126 (9,866)18,260 
Contingent consideration— — 16,304 16,304 — 16,304 
Liabilities:
Current:
Commodity— 2,638 — 2,638 (2,638)— 
Noncurrent:
Commodity— (15,680)— (15,680)9,866 (5,814)
Net derivative asset positions$— $113,909 $16,315 $130,224 $— $130,224 

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Table of ContentsVital Energy, Inc.
Notes to the consolidated financial statements
December 31, 2023
(in thousands)Level 1Level 2Level 3Total gross fair valueAmounts offsetNet fair value presented on the consolidated balance sheets
Assets:
Current:
Commodity$— $106,067 $— $106,067 $(9,032)$97,035 
Contingent consideration— — 2,301 2,301 — 2,301 
Noncurrent:
Commodity— 22,266 — 22,266 — 22,266 
Contingent consideration— — 28,805 28,805 — 28,805 
Liabilities:
Current:
Commodity— (9,032)— (9,032)9,032 — 
Net derivative asset positions$— $119,301 $31,106 $150,407 $— $150,407 
Commodity
Significant Level 2 inputs associated with the calculation of discounted cash flows used in the fair value mark-to-market analysis of commodity derivatives include each commodity derivative contract's corresponding commodity index price(s), forward price curve models for substantially similar instruments and counterparty risk-adjusted discount rates generated from a compilation of data gathered by a third-party valuation specialist. The Company reviewed the third-party specialist's valuations of commodity derivatives, including the related inputs, and analyzed changes in fair values between reporting dates.
Contingent consideration
The Sixth Street Contingent Consideration was categorized as Level 3, as the Company utilized its own cash flow projections along with a risk-adjusted discount rate generated by a third-party valuation specialist to determine the valuation. The Company reviewed the third-party specialist's valuation, including the related inputs, and analyzed changes in fair values between the divestiture closing date and the reporting dates. The fair value of the Sixth Street Contingent Consideration was recorded as part of the basis in the oil and natural gas properties divested and as a contingent consideration asset. At each quarterly reporting period, the Company remeasures contingent consideration with the change in fair values recognized in "Gain (loss) on derivatives, net" under "Non-operating income (expense)" on the consolidated statement of operations.
The following table summarizes the changes in contingent consideration derivatives classified as Level 3 measurements for the periods presented:
Years ended December 31,
(in thousands)202420232022
Balance of Level 3 at beginning of year$31,106 $26,640 $35,861 
Change in Sixth Street Contingent Consideration fair value(14,791)6,279 (6,764)
Settlements realized(1)
— (1,813)(2,457)
Balance of Level 3 at end of year$16,315 $31,106 $26,640 
_____________________________________________________________________________
(1)Amounts are included in "Other, net" in cash flows from investing activities on the consolidated statements of cash flows.
Items not accounted for at fair value
The carrying amounts reported on the consolidated balance sheets for cash and cash equivalents, accounts receivable, accounts payable, accrued capital expenditures, undistributed revenue and royalties and other accrued assets and liabilities approximate their fair values.
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Notes to the consolidated financial statements
The Company has not elected to account for its debt instruments at fair value. The following table presents the carrying amounts and fair values of the Company's debt as of the dates presented:
December 31, 2024December 31, 2023
(in thousands)
Carrying
amount(1)
Fair value(2)
Carrying
amount(1)
Fair value(2)
Debt$2,480,578 $2,455,032 $1,633,523 $1,658,686 
_____________________________________________________________________________
(1)Amounts presented do not include issuance premiums or discounts.
(2)The fair values of the outstanding notes were determined using the Level 2 fair value hierarchy quoted market prices for each respective instrument as of December 31, 2024 and 2023. The fair values of the outstanding amounts under the Senior Secured Credit Facility approximate the carrying values based on short-term floating interest rates available to the Company as of December 31, 2024 and 2023.
Note 13
Income taxes
The Company is subject to federal and state income taxes and the Texas franchise tax. The following table presents the "Current" and "Deferred" income tax benefit (expense) reported on the consolidated statements of operations for the periods presented:
Years ended December 31,
(in thousands)202420232022
Current income tax benefit (expense):
Federal$— $— $— 
State(2,456)(5,723)(6,121)
Deferred income tax benefit (expense):
Federal47,254 190,341 — 
State2,942 (1,281)619 
Total income tax benefit (expense):$47,740 $183,337 $(5,502)
Total income tax benefit (expense) differed from amounts computed by applying the applicable federal income tax rate of 21% for the years ended December 31, 2024, 2023 and 2022 to pre-tax earnings as a result of the following:
Years ended December 31,
(in thousands)202420232022
Income tax benefit (expense) computed by applying the statutory rate$46,465 $(107,466)$(133,773)
Change in deferred tax valuation allowance— 297,658 144,480 
Non-deductible equity-based compensation— — (19,301)
State income tax and change in state valuation allowance(609)(5,803)8,058 
Other items1,884 (1,052)(4,966)
Total income tax benefit (expense)$47,740 $183,337 $(5,502)
The Company is required to estimate the federal and state income taxes in each of the jurisdictions it operates in. This process involves estimating the actual current tax exposure together with assessing temporary differences resulting from differing treatment of items for tax and financial accounting purposes. These differences and the Company's net operating loss ("NOL") carryforwards result in deferred tax assets and liabilities.
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Table of ContentsVital Energy, Inc.
Notes to the consolidated financial statements
The following table presents significant components of the Company's net deferred tax asset as of the dates presented:
(in thousands)December 31, 2024December 31, 2023
Deferred tax assets:
Net operating loss carryforwards$206,752 $264,114 
Oil and natural gas properties, midstream service assets and other fixed assets49,765 — 
Equity-based compensation1,703 232 
Interest expense limitation20,599 3,908 
Other6,585 4,117 
Total deferred tax assets285,404 272,371 
Valuation allowance(18,372)(20,145)
Deferred tax assets, net of valuation allowance267,032 252,226 
Deferred tax liabilities:
Oil and natural gas properties, midstream service assets and other fixed assets— (36,524)
Derivatives(27,347)(25,353)
Other— (1,513)
Total deferred tax liabilities(27,347)(63,390)
Total net deferred tax asset(1)
$239,685 $188,836 
___________________________________________________________________________
(1)The net deferred tax asset as of December 31, 2024 and 2023 is included in "Deferred income taxes" on the consolidated balance sheet.
As of December 31, 2024, the Company had federal NOL carryforwards totaling $897.0 million, of which $530.2 million is subject to expiration and will begin to expire in 2035 and $366.8 million of which will not expire but may be limited in future periods, and state of Oklahoma NOL carryforwards totaling $459.3 million, none of which will expire.
As of December 31, 2024, the Company had approximately $239.7 million in net deferred tax assets, which are primarily the result of U.S. NOL carryforwards of 206.8 million, that can be used to offset taxable income in future periods and reduce the Company's income taxes payable in those future periods. Some of these NOL carryforwards will expire if they are not used within certain periods.
At this time, the Company considers it more-likely-than-not that it will have sufficient taxable income in the future that will allow the utilization of its federal NOL carryforwards and realize its deferred tax assets. However, it is possible that some or all of these NOL carryforwards, that are subject to expiration could ultimately expire unused and prevent us from realizing the full value of the deferred tax assets. Our assessment relies on the ability to forecast sufficient taxable income from operations, however any future impairments, as a result of the full cost ceiling limitation, may limit that reliance. As a result, a full or partial valuation allowance to reduce the Company's deferred tax assets may be required, which would materially increase its expenses in the period the allowance is recognized. As of December 31, 2024, the Company continues to maintain a full valuation allowance against its state of Oklahoma deferred tax assets.
A valuation allowance of $298.2 million was recorded against the gross deferred tax asset balance as of December 31, 2022, on the basis of management’s assessment that its deferred tax assets did not meet the standard for recognition. As of each reporting date, the Company considers new evidence, both positive and negative, that could affect its view of the future realization of deferred tax assets. During the year ended December 31, 2023, the Company determined that there was sufficient positive evidence to conclude that it is more-likely-than-not its federal deferred tax assets are realizable. For the year ended December 31, 2023, the Company recorded $183.3 million of tax benefit, which is primarily attributable to the release of the valuation allowance.
The Company's effective tax rate is affected by changes in valuation allowances, recurring permanent differences and discrete items that may occur in any given year, but are not consistent from year to year. For the year ended December 31, 2024, the Company's effective tax rate was 21.6% and the current tax expense was related to Texas franchise tax. For the year ended December 31, 2023, the Company's effective tax rate was not meaningful due to the release of its valuation allowance. For the year ended December 31, 2022, the Company had recorded a full valuation allowance against its federal and Oklahoma
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Table of ContentsVital Energy, Inc.
Notes to the consolidated financial statements
net deferred tax asset position and the only tax expense was related to Texas franchise tax. For the years ended December 31, 2024 and 2022, the Company’s items of discrete income tax expense or benefit were not material.
If the Company were to experience an "ownership change" as determined under Section 382 of the Internal Revenue Code, the Company's ability to offset taxable income arising after the ownership change with NOLs arising prior to the ownership change could be significantly limited. Based on information available as of February 15, 2025, no such ownership change has occurred.
On August 16, 2022, the U.S. Inflation Reduction Act of 2022 (the "IRA") was signed into U.S. law. The IRA includes various tax provisions, including a 1% excise tax on stock repurchases made by publicly traded U.S. corporations and a 15% corporate alternative minimum tax ("CAMT") that applies to certain corporations with adjusted financial statement income in excess of $1.0 billion. Based on the Company's interpretation of the IRA, CAMT and related guidance, the Company does not expect the CAMT to impact its tax obligation for the 2024 taxable year; however, the 1% excise tax on stock repurchases will apply to the share repurchase program. The Company continues to evaluate the IRA and its effect on the Company's financial results and operating cash flows.
The Company closed two acquisitions during 2024. For income tax purposes, both the PEP Acquisition and the Point Acquisition were treated as asset purchases. As such, the tax basis in the assets and liabilities will generally reflect the allocated fair value at closing. Therefore, the Company did not record any deferred income taxes as part of the purchase consideration. See Note 3 for additional information regarding the Company's acquisitions.
Note 14
Credit risk
Financial instruments that potentially subject the Company to a concentration of credit risk consist of cash and cash equivalents, accounts receivable and commodity derivatives. The Company places its cash and cash equivalents with high credit quality financial institutions. The Company currently uses commodity derivatives to hedge its exposure to commodity prices. These transactions expose the Company to potential credit risk from its counterparties. The Company has entered into International Swaps and Derivatives Association Master Agreements ("ISDA Agreements") with each of its commodity derivative counterparties, each of whom is also a lender in its Senior Secured Credit Facility, which, together with hedge agreements with lenders under such facility, is secured by its oil, NGL and natural gas reserves; therefore, the Company is not required to post any additional collateral. The Company does not require collateral from its commodity derivative counterparties. The terms of the ISDA Agreements provide the non-defaulting or non-affected party the right to terminate the agreement upon the occurrence of certain events of default and termination events by a party and also provide for the marking to market of outstanding positions and the offset of the mark to market amounts owed to and by the parties (and in certain cases, the affiliates of the non-defaulting or non-affected party) upon termination; therefore, the credit risk associated with its commodity derivative counterparties is somewhat mitigated. The Company minimizes the credit risk in commodity derivatives by: (i) limiting its exposure to any single counterparty, (ii) entering into commodity derivatives only with counterparties that meet its minimum credit quality standard or have a guarantee from an affiliate that meets its minimum credit quality standard and (iii) monitoring the creditworthiness of its counterparties on an ongoing basis. As of December 31, 2024, the Company had a net asset position of $113.9 million from the fair values of its open commodity derivative contracts. See "Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk" located elsewhere in this Annual Report and Notes 2, 11, 12 and 18 for additional information regarding the Company's derivatives.
The Company typically sells production to a relatively limited number of customers, as is customary in the exploration, development and production business. The Company's sales of purchased oil are generally made to a few customers. The Company's joint operations accounts receivable are from a number of oil and natural gas companies, partnerships, individuals and others who own interests in the oil and natural gas properties operated by the Company.
The majority of the Company's accounts receivable are unsecured. On occasion the Company requires its customers to post collateral, and the inability or failure of the Company's significant customers to meet their obligations to the Company or their insolvency or liquidation may adversely affect the Company's financial results. In the current market environment, the Company believes that it could sell its production to numerous companies, so that the loss of any one of its major purchasers would not have a material adverse effect on its financial condition and results of operations solely by reason of such loss. Additionally, management believes that any credit risk imposed by a concentration in the oil and natural gas industry is offset by the creditworthiness of the Company's customer base and industry partners. The Company routinely assesses the
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Table of ContentsVital Energy, Inc.
Notes to the consolidated financial statements
recoverability of all material trade and other receivables to determine collectability. See Note 2 for additional information regarding the Company's accounts receivable and revenue recognition.
The following table presents purchasers that individually accounted for 10% or more of the Company's oil, NGL and natural gas sales in at least one of the years presented:
Years ended December 31,
202420232022
Purchaser A24 %
N/A(1)
N/A(1)
Purchaser B17 %32 %33 %
Purchaser C17 %21 %
N/A(1)
Purchaser D
N/A(1)
N/A(1)
18 %
Purchaser E
N/A(1)
N/A(1)
17 %
Purchaser F
N/A(1)
12 %
N/A(1)
_____________________________________________________________________________
(1)    This purchaser did not account for 10% or greater of the Company's oil, NGL and natural gas sales during the indicated period.
For the years ended December 31, 2024, 2023 and 2022, the Company's sales of purchased oil represented less than 10% of total revenue.
Note 15
Commitments and contingencies
From time to time, the Company is subject to various legal proceedings arising in the ordinary course of business, including those that arise from interpretation of federal, state and local laws and regulations affecting the oil and natural gas industry, personal injury claims, title disputes, royalty disputes, contract claims, contamination claims relating to oil and natural gas exploration and development and environmental claims, including claims involving assets previously sold to third parties and no longer part of the Company's current operations. The Company may not have insurance coverage for some of these proceedings and failure to comply with applicable laws and regulations can result in substantial penalties. While many of these matters involve inherent uncertainty, as of the date hereof, the Company believes that any such legal proceedings, if ultimately decided adversely, will not have a material adverse effect on the Company's business, financial position, results of operations or liquidity.
The Company has committed to deliver, for sale or transportation, fixed volumes of product under certain contractual arrangements that specify the delivery of a fixed and determinable quantity. If not fulfilled, the Company is subject to firm transportation payments on excess pipeline capacity and other contractual penalties. These commitments are normal and customary for the Company's business. In certain instances, the Company has used spot market purchases to meet its commitments in certain locations or due to favorable pricing. As of December 31, 2024, future firm sale and transportation commitments of $88.0 million are expected to be satisfied and, as such, are not recorded as a liability on the consolidated balance sheet.
The Company has committed to purchase a fixed supply of electricity at specified prices through 2029. As of December 31, 2024, future minimum payments under the terms of this agreement are $187.0 million.
The Company has committed to take delivery of processed sand, which is utilized in the Company's completions activities, at specified prices through 2026. As of December 31, 2024, future minimum purchase commitments under the terms of these agreements are estimated to be $40.8 million.
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Table of ContentsVital Energy, Inc.
Notes to the consolidated financial statements
Note 16
Related parties
Halliburton
The Chairman of the Company's board of directors is on the board of directors of Halliburton Company ("Halliburton"). Halliburton provides drilling and completions services to the Company. The Company has a lease agreement with Halliburton, which became effective during the first quarter of 2023 and extends through 2025, to provide an electric fracture stimulation crew and the related services. Under the agreement, the Company had a lease liability of $24.0 million as of December 31, 2024 and $59.7 million as of December 31, 2023, which is included in both current and noncurrent "Operating lease liabilities" on the consolidated balance sheets. Services provided under the lease agreement do not differ substantially from historical services provided by Halliburton, which were previously not subject to a long-term agreement. Payments to Halliburton are included in capital expenditures for oil and natural gas properties in cash flows from investing activities on the consolidated statements of cash flows.
The following table presents the capital expenditures for oil and natural gas properties paid to Halliburton included in the consolidated statements of cash flows for the periods presented:
Years ended December 31,
(in thousands)202420232022
Capital expenditures for oil and natural gas properties$86,006 $113,291 $103,152 
Note 17
Segment reporting
The Company engages in a single activity, the exploration and development of oil and natural gas properties in the Permian Basin of West Texas, and, as such, has one reportable segment based upon the Company’s current organizational and management structure. The accounting policies for the segment, including those related to revenue, are the same as those described in Note 2. Net income (loss), which is reported on the consolidated statements of operations, is the metric most consistent with GAAP that the Company uses to evaluate its performance and make decisions around the timing and allocation of capital investments and debt reduction. The Company does not use a measure of segment assets in its decision making. The Company’s chief operating decision maker (“CODM”) is the Senior Executive Team. There are no significant expense categories regularly provided to the CODM beyond those disclosed in the consolidated statements of operations.
Note 18
Subsequent events
Senior Secured Credit Facility
Subsequent to December 31, 2024, the Company borrowed $90.0 million and repaid $115.0 million on the Senior Secured Credit Facility. As a result, the outstanding balance under the Senior Secured Credit Facility was $855.0 million as of February 19, 2025. See Note 7 for additional discussion of the Senior Secured Credit Facility.
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Table of ContentsVital Energy, Inc.
Notes to the consolidated financial statements
Commodity derivatives
The following table summarizes the Company's open oil and natural gas derivative positions as of December 31, 2024, updated for the derivative transactions entered into from December 31, 2024 through February 19, 2025, for the settlement periods presented:
Year 2025Year 2026Year 2027
Oil:
WTI NYMEX - Swaps:
Volume (Bbl)17,433,000 4,005,000 — 
Weighted-average price ($/Bbl)$74.75 $71.42 $— 
NGL:
Non-TET Propane - Swaps:
Volume (Bbl)3,131,000 — — 
Weighted-average price ($/Bbl)$34.16 $— $— 
Non-TET Ethane - Swaps:
Volume (Bbl)3,938,000 — — 
Weighted-average price ($/Bbl)$11.04 $— $— 
Natural gas:
Waha Inside FERC - Swaps:
Volume (MMBtu)42,705,000 44,530,000 43,800,000 
Weighted-average price ($/MMBtu)$2.31 $2.43 $2.70 
See Note 11 for additional discussion regarding the Company's derivatives. There has been no other derivative activity subsequent to December 31, 2024.


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Table of ContentsVital Energy, Inc.
Unaudited Supplementary Information
Supplemental oil, NGL and natural gas disclosures
Costs incurred in oil and natural gas property acquisition, exploration and development activities
The following table presents costs incurred in the acquisition, exploration and development of oil and natural gas properties, with asset retirement obligations included in evaluated property acquisition costs and development costs, for the periods presented:
Years ended December 31,
(in thousands)202420232022
Property acquisition costs:
Evaluated$878,359 $1,328,571 $8,295 
Unevaluated83,242 401,533 3,470 
Exploration costs27,128 29,612 26,384 
Development costs846,509 633,413 540,447 
Total oil and natural gas properties costs incurred$1,835,238 $2,393,129 $578,596 
Aggregate capitalized oil, NGL and natural gas costs
The following table presents the aggregate capitalized costs related to oil, NGL and natural gas production activities with applicable accumulated depletion and impairment as of the dates presented:
(in thousands)December 31, 2024December 31, 2023
Gross capitalized costs:
Evaluated properties$13,587,040 $11,799,155 
Unevaluated properties not being depleted242,792 195,457 
Total gross capitalized costs13,829,832 11,994,612 
Less accumulated depletion and impairment(8,966,200)(7,764,697)
Net capitalized costs$4,863,632 $4,229,915 
The following table presents a summary of the unevaluated property costs not being depleted as of December 31, 2024, by year in which such costs were incurred:
(in thousands)2024202320222021 and priorTotal
Unevaluated properties not being depleted$117,789 $106,094 $695 $18,214 $242,792 
Unevaluated properties, which are not subject to depletion, are not individually significant and consist of costs for acquiring oil and natural gas leasehold where no evaluated reserves have been identified, including costs of wells being evaluated. The evaluation process associated with these properties has not been completed and therefore, the Company is unable to estimate when these costs will be included in the depletion calculation.

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Table of ContentsVital Energy, Inc.
Unaudited Supplementary Information
Results of operations of oil, NGL and natural gas producing activities
The following table presents the results of operations of oil, NGL and natural gas producing activities (excluding corporate overhead and interest costs) for the periods presented:
Years ended December 31,
(in thousands)202420232022
Revenues:
Oil, NGL and natural gas sales$1,935,290 $1,528,633 $1,794,374 
Production costs:
Lease operating expenses448,078 261,129 173,983 
Production and ad valorem taxes117,947 93,224 110,997 
Oil transportation and marketing expenses44,843 41,284 53,692 
Gas gathering, processing and transportation expenses17,825 2,013 — 
Total production costs628,693 397,650 338,672 
Other costs:
Depletion720,190 446,611 298,259 
Accretion of asset retirement obligation3,918 3,518 3,653 
Impairment expense481,305 — — 
Income tax expense(1)
22,260 149,788 11,538 
Total other costs1,227,673 599,917 313,450 
Results of operations$78,924 $531,066 $1,142,252 
_____________________________________________________________________________
(1)During the year ended December 31, 2022, the Company recorded a full valuation allowance against its deferred tax assets related to its oil, NGL and natural gas producing activities. Accordingly, the income tax expense was computed utilizing the Company's effective tax rate of 1% for the year ended December 31, 2022. During 2023, the Company determined that there was sufficient positive evidence to conclude that it is more-likely-than-not its federal deferred tax assets are realizable and released the valuation allowance. As such, the income tax expense for the years ended December 31, 2024 and 2023 is calculated using the statutory rate of 22%.
Net proved oil, NGL and natural gas reserves
Ryder Scott Company, L.P. ("Ryder Scott"), the Company's independent reserve engineers, estimated 100% of the Company's proved reserves as of December 31, 2024, 2023 and 2022. In accordance with SEC regulations, the reserves as of December 31, 2024, 2023 and 2022 were estimated using the Realized Prices, which reflect adjustments to the Benchmark Prices for quality, certain transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the delivery point. See Note 6 for these Realized Prices. The Company's reserves are reported in three streams: oil, NGL and natural gas.
The SEC has defined proved reserves as the estimated quantities of oil, NGL and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The process of estimating oil, NGL and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material.
F-43
Table of ContentsVital Energy, Inc.
Unaudited Supplementary Information
The following tables provide an analysis of the changes in estimated proved reserve quantities of oil, NGL and natural gas for the years ended December 31, 2024, 2023 and 2022, all of which are located within the U.S.:
Oil
(MBbl)		NGL
(MBbl)		Natural gas
(MMcf)		MBOE
Proved developed and undeveloped reserves:
As of December 31, 2021120,902 100,047 586,145 318,640 
Revisions of previous estimates(9,792)(4,561)(14,694)(16,802)
Extensions, discoveries and other additions21,351 7,162 33,767 34,141 
Divestitures of reserves in place(2,165)(808)(3,671)(3,585)
Production(13,838)(8,028)(49,259)(30,076)
As of December 31, 2022116,458 93,812 552,288 302,318 
Revisions of previous estimates(28,564)(20,823)(55,284)(58,601)
Extensions, discoveries and other additions11,175 10,281 56,329 30,844 
Acquisitions of reserves in place77,609 47,261 244,253 165,578 
Production(16,895)(9,128)(55,404)(35,256)
As of December 31, 2023159,783 121,403 742,182 404,883 
Revisions of previous estimates(24,165)(2,402)(55,420)(35,805)
Extensions, discoveries and other additions29,119 18,859 109,190 66,177 
Acquisitions of reserves in place40,988 15,060 77,751 69,007 
Production(22,585)(13,270)(78,794)(48,987)
As of December 31, 2024183,140 139,650 794,909 455,275 
Proved developed reserves:
December 31, 202170,727 78,908 494,476 232,048 
December 31, 202270,333 75,156 464,567 222,917 
December 31, 2023104,993 89,449 555,472 287,021 
December 31, 2024118,966 101,229 587,785 318,159 
Proved undeveloped reserves:
December 31, 202150,175 21,139 91,669 86,592 
December 31, 202246,125 18,656 87,721 79,401 
December 31, 202354,790 31,954 186,710 117,862 
December 31, 202464,174 38,421 207,124 137,116 
The following discussion is for the year ended December 31, 2024.
•Revisions of previous estimates consisted of (i) 27,033 MBOE of negative revisions due to proved undeveloped locations that were removed due to a change in the five-year development plan following consideration of recent acquisitions, (ii) 10,910 MBOE of negative revisions from a decrease in the Realized Prices for oil, NGL and natural gas, (iii) 1,220 MBOE of negative revisions due to changes in performance and other economic assumptions on proved wells and locations and (iv) 3,358 MBOE of positive revisions due to the inclusion of proved undeveloped locations that were removed from the development plan in prior years.
•Extensions, discoveries and other additions consisted of (i) 6,094 MBOE from proved developed locations and (ii) 60,083 MBOE for new horizontal proved undeveloped locations, added in the Company’s acreage in both the Delaware and Midland Basins.
•Acquisitions of reserves in place consisted of (i) 34,880 MBOE from proved developed producing wells, (ii) 27,072 MBOE from proved undeveloped producing wells and (iii) 7,055 MBOE of additional reserves from proved developed producing wells already operated by the company.
•The Company converted 40,914 MBOE of proved undeveloped reserves into proved developed reserves in 2024.
F-44
Table of ContentsVital Energy, Inc.
Unaudited Supplementary Information
The following discussion is for the year ended December 31, 2023.
•Revisions of previous estimates consisted of (i) 16,240 MBOE of negative revisions from performance of proved developed producing wells, (ii) 4,470 MBOE of positive revisions from an increase in previously estimated quantities of proved undeveloped locations, (iii) 8,679 MBOE of negative revisions from a decrease in the Realized Prices for oil, NGL and natural gas, (iv) 12,030 MBOE of negative revisions from changes to economic assumptions on proved wells and (v) 26,122 MBOE of negative revisions due to 45 proved undeveloped locations that were removed from the development plan.
•Extensions, discoveries and other additions consisted of 30,246 MBOE that resulted from new horizontal proved undeveloped locations added in the Company's acreage in Howard County, Texas and Western Glasscock Counties, Texas.
•Acquisitions of reserves in place consisted of (i) 104,323 MBOE from proved developed producing wells and (ii) 61,255 MBOE from proved undeveloped locations.
The following discussion is for the year ended December 31, 2022.
•Revisions of previous estimates consisted of (i) 9,531 MBOE of negative revisions from performance of proved developed producing wells, (ii) 1,837 MBOE of negative revisions from a decrease in previously estimated quantities of proved undeveloped locations, (iii) 4,351 MBOE of positive revisions from an increase in the Realized Prices for oil, NGL and natural gas and other changes to proved wells and (iv) 9,785 MBOE of negative revisions due to 16 proved undeveloped locations that were removed from the development plan.
•Extensions, discoveries and other additions consisted of (i) 3,850 MBOE that resulted from new wells drilled and (ii) 30,291 MBOE that resulted from new horizontal proved undeveloped locations added in the Company's acreage in Howard and western Glasscock Counties.
•Divestiture of reserves in place related to the divestment of non-operated properties in Howard County.
Standardized measure of discounted future net cash flows
The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil, NGL and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of proved properties and consideration of expected future economic and operating conditions.
The estimates of future cash flows and future production and development costs as of December 31, 2024, 2023 and 2022 are based on the Realized Prices, which reflect adjustments to the Benchmark Prices for quality, certain transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the delivery point. All Realized Prices are held flat over the forecast period for all reserve categories in calculating the discounted future net cash flows. Any effect from the Company's commodity hedges is excluded. In accordance with SEC regulations, the proved reserves were anticipated to be economically producible from the "as of date" forward based on existing economic conditions, including prices and costs at which economic producibility from a reservoir was determined. These costs, held flat over the forecast period, include development costs, operating costs, ad valorem and production taxes and abandonment costs after salvage. Future income tax expenses are computed using the appropriate year-end statutory tax rates applied to the future pretax net cash flows from proved oil, NGL and natural gas reserves, less the tax basis of the Company's oil and natural gas properties. The estimated future net cash flows are then discounted at a rate of 10%. The Company's unamortized cost of evaluated oil and natural gas properties exceeded the full cost ceiling for the fourth quarter of 2024 and, as such, the Company recorded a non-cash full cost ceiling impairment of $481.3 million during the year ended December 31, 2024. No full cost ceiling impairment was recorded for the years ended December 31, 2023 and 2022. See Note 6 for discussion of the Benchmark Prices and Realized Prices.
F-45
Table of ContentsVital Energy, Inc.
Unaudited Supplementary Information
The following table presents the standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves for the periods presented:
Years ended December 31,
(in thousands)202420232022
Future cash inflows$16,640,461 $15,570,267 $16,343,468 
Future production costs(6,466,648)(5,543,237)(4,136,380)
Future development costs(2,155,788)(1,904,597)(1,403,721)
Future income tax expenses(538,142)(669,158)(1,587,677)
Future net cash flows7,479,883 7,453,275 9,215,690 
10% discount for estimated timing of cash flows
(3,264,563)(3,302,437)(4,461,114)
Standardized measure of discounted future net cash flows$4,215,320 $4,150,838 $4,754,576 
It is not intended that the FASB's standardized measure of discounted future net cash flows represent the fair market value of the Company's proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, prices and costs as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves.
The following table presents the changes in the standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves for the periods presented:
Years ended December 31,
(in thousands)202420232022
Standardized measure of discounted future net cash flows, beginning of year$4,150,838 $4,754,576 $3,425,312 
Changes in the year resulting from:
Sales, less production costs(1,308,530)(1,136,735)(1,468,946)
Revisions of previous quantity estimates(105,561)(964,416)(99,512)
Extensions, discoveries and other additions412,846 125,875 667,859 
Net change in prices and production costs(877,407)(2,560,883)2,565,963 
Changes in estimated future development costs(48,987)137,310 (165,579)
Previously estimated development costs incurred during the period461,230 368,688 260,475 
Acquisitions of reserves in place982,594 2,211,370 — 
Divestitures of reserves in place— — (96,222)
Accretion of discount448,835 624,819 371,625 
Net change in income taxes43,168 371,962 (418,537)
Timing differences and other56,294 218,272 (287,862)
Standardized measure of discounted future net cash flows, end of year$4,215,320 $4,150,838 $4,754,576 
Estimates of economically recoverable oil, NGL and natural gas reserves and of future net cash flows are based upon a number of variable factors and assumptions, all of which are, to some degree, subjective and may vary considerably from actual results. Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions as to geologic formations and other matters. Actual quantities of oil, NGL and natural gas may differ materially from the amounts estimated.
F-46
Exhibit 99.4
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES FOR EAGLE FORD OIL AND GAS PROPERTIES
INDEX
Financial Information
Independent Auditors' Report
2
Statements of Revenues and Direct Operating Expenses
4
Notes to Statements of Revenues and Direct Operating Expenses
5
1
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KPMG LLP
811 Main Street
Houston, TX 77002
Independent Auditors’ Report
To the Board of Directors
Devon Energy Corporation:
Report on the Audit of the Statements of Revenues and Direct Operating Expenses
Opinion
We have audited the accompanying statements of revenues and direct operating expenses of certain oil and natural gas properties of Devon Energy Corporation (the Company) located in the Eagle Ford (Properties) for the years ended December 31, 2025 and 2024 (collectively referred to as the financial statements).
In our opinion, the financial statements present fairly, in all material respects, the revenues and direct operating expenses of the Properties for the years ended December 31, 2025 and 2024 in accordance with U.S. generally accepted accounting principles.
Basis for Opinion
We conducted our audits in accordance with auditing standards generally accepted in the United States of America (GAAS). Our responsibilities under those standards are further described in the Auditors’ Responsibilities for the Audit of the Financial Statements section of our report. We are required to be independent of the Company and to meet our other ethical responsibilities, in accordance with the relevant ethical requirements relating to our audits. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
Basis of Accounting
As discussed in Note 1 to the financial statements, the accompanying financial statements referred to above were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission. The financial statements are not intended to be a complete presentation of the operations of the Properties.
Other Matter
U.S. generally accepted accounting principles require that the Supplementary Oil and Gas Disclosures contained herein be presented to supplement the basic financial statements. Such information, although not a part of the basic financial statements, is required by the Financial Accounting Standards Board who considers it to be an essential part of the financial reporting for placing the basic financial statements in an appropriate operational, economic, or historical context. We have applied certain limited procedures to the required supplementary information in accordance with auditing standards generally accepted in the United States of America, which consisted of inquiries of management about the methods of preparing the information and comparing the information for consistency with management’s responses to our inquiries, the basic financial statements, and other knowledge we obtained during our audit of the basic financial statements. We do not express an opinion or provide any assurance on the information because the limited procedures do not provide us with sufficient evidence to express an opinion or provide any assurance.
Responsibilities of Management for the Financial Statements
Management is responsible for the preparation and fair presentation of the financial statements in accordance with U.S. generally accepted accounting principles, and for the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.
2
KPMG LLP, a Delaware limited liability partnership, and its subsidiaries are part of the KPMG global organization of independent member firms affiliated with KPMG International Limited, a private English company limited by guarantee.
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In preparing the financial statements, management is required to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the Properties’ ability to continue as a going concern for one year after the date that the financial statements are issued.
Auditors’ Responsibilities for the Audit of the Financial Statements
Our objectives are to obtain reasonable assurance about whether the financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditors’ report that includes our opinion. Reasonable assurance is a high level of assurance but is not absolute assurance and therefore is not a guarantee that an audit conducted in accordance with GAAS will always detect a material misstatement when it exists. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control. Misstatements are considered material if there is a substantial likelihood that, individually or in the aggregate, they would influence the judgment made by a reasonable user based on the financial statements.
In performing an audit in accordance with GAAS, we:
●Exercise professional judgment and maintain professional skepticism throughout the audit.
●Identify and assess the risks of material misstatement of the financial statements, whether due to fraud or error, and design and perform audit procedures responsive to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements.
●Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control. Accordingly, no such opinion is expressed.
●Evaluate the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluate the overall presentation of the financial statements.
●Conclude whether, in our judgment, there are conditions or events, considered in the aggregate, that raise substantial doubt about the Properties’ ability to continue as a going concern for a reasonable period of time.
We are required to communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audit, significant audit findings, and certain internal control related matters that we identified during the audit.
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Houston, Texas
September 30, 2026
3

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES FOR EAGLE FORD OIL AND GAS PROPERTIES
Years Ended December 31, 2025 and December 31, 2024, and
Six Months Ended June 30, 2026 and June 30, 2025
(in thousands)
Six Months Ended June 30, Year Ended December 31,
2026202520252024
(unaudited)
(audited)
Operating revenues$787,129 $473,580 $996,743 $1,107,685 
Direct operating expenses163,156 126,114 264,953 242,821 
Excess of revenues over direct operating expenses$623,973 $347,466 $731,790 $864,864 
The accompanying notes are an integral part of the Statements of Revenues and Direct Operating Expenses.
4
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES FOR EAGLE FORD OIL AND GAS PROPERTIES
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
Note 1 – Basis of Presentation
The accompanying statements present the revenues and direct operating expenses of certain oil and natural gas properties located in the Eagle Ford Shale in South Texas (the "Properties"), which Devon Energy Corporation ("Devon"), through certain of its wholly-owned subsidiaries, has offered for sale. As of the date of these statements, no purchase and sale agreement has been executed, and the scope of any transaction, the identity of any purchaser and the consideration to be received have not been determined.
The accompanying statements of revenues and direct operating expenses were prepared from the historical accounting records of Devon. These statements are not intended to be a complete financial presentation of the results of operations of the Properties. The statements do not include general and administrative expense, effects of derivative transactions, interest income or expense, depreciation, depletion and amortization, any provision for income tax expenses and other income and expense items not directly associated with the Properties. Historical financial statements reflecting financial position, results of operations and cash flows required by accounting principles generally accepted in the United States of America ("GAAP") are not presented as such information is not readily available and not meaningful to the Properties. Accordingly, the accompanying statements of revenues and direct operating expenses are presented in lieu of the financial statements required under Rule 3-05 of Securities and Exchange Commission ("SEC") Regulation S-X.
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions about future events that affect the reported amounts of revenues and expenses during the reporting period. These estimates and assumptions are based on Devon management's best estimates and judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from these estimates.
Acreage Exchange with BPX Energy
On April 1, 2025, Devon and BPX Energy, Inc. dissolved their partnership and divided their acreage in the Eagle Ford Blackhawk field located in Texas' DeWitt County. The assets exchanged were in close proximity and shared similar geological characteristics. The transaction was accounted for as an equal, non-monetary exchange as it did not result in a significant change to the risks, expected future cash flows or the timing of those cash flows, and therefore was determined to lack commercial substance. As a result, the new acreage and the underlying property costs were recorded at the historical carrying amount of the assets exchanged. Because these statements exclude depreciation, depletion and amortization, the exchange had no effect on the revenues or direct operating expenses presented other than through the change in the composition of Devon's interests.
Revenues and direct operating expenses for periods prior to April 1, 2025 reflect only the interests Devon held in that acreage during those periods, as recorded in Devon's historical accounting records. They have not been adjusted on a pro forma basis as though the post-exchange interests had been held throughout the periods presented.
Operating Revenues
Operating revenues include the sale of oil, gas and NGL production. Oil, gas and NGL sales are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, control has transferred and collectability of the revenue is probable. Devon's performance obligations are satisfied at a point in time. This occurs when control is transferred to the purchaser upon delivery of contract specified production volumes at a specified point. The transaction price used to recognize revenue is a function of the contract billing terms. Revenue is invoiced, if required, by calendar month based on volumes at contractually based rates with payment typically received within 30 days of the end of the production month. Taxes assessed by governmental authorities on oil, gas and NGL sales are presented separately from such revenues in the statements of revenues and direct operating expenses. Revenue is recognized on a production date basis.
5
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES FOR EAGLE FORD OIL AND GAS PROPERTIES
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
Oil sales
Devon’s oil sales contracts are generally structured in one of two ways. First, production is sold at the wellhead at an agreed-upon index price, net of pricing differentials. In this scenario, revenue is recognized when control transfers to the purchaser at the wellhead at the net price received. Alternatively, production is delivered to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product. Under this arrangement, a third party is paid to transport the product and Devon receives a specified index price from the purchaser with no transportation deduction. In this scenario, revenue is recognized when control transfers to the purchaser at the delivery point based on the price received from the purchaser. The third-party costs are recorded as gathering, processing and transportation expense as a component of direct operating expenses in the statements of revenues and direct operating expenses.
Natural gas and NGL sales
Under Devon’s natural gas processing contracts, natural gas is delivered to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds for the resulting sales of NGLs and residue gas. In these scenarios, Devon evaluates whether it is the principal or the agent in the transaction. Devon has concluded it is the principal under these contracts and the ultimate third party is the customer. Revenue is recognized on a gross basis, with gathering, processing and transportation fees presented as a component of direct operating expenses in the statements of revenues and direct operating expenses.
In certain natural gas processing agreements, Devon may elect to take residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, the product is delivered to the ultimate third-party purchaser at a contractually agreed-upon delivery point, and Devon receives a specified index price from the purchaser. In this scenario, revenue is recognized when control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as gathering, processing and transportation expense as a component of direct operating expenses in the statements of revenues and direct operating expenses.
Satisfaction of Performance Obligations and Revenue Recognition
Since Devon has a right to consideration from its customers in amounts that correspond directly to the value that the customer receives from the performance completed on each contract, Devon applies the practical expedient that allows recognition of revenue in the amount to which there is a right to invoice and prevents the need to estimate a transaction price for each contract and allocating that transaction price to the performance obligations within each contract. Devon recognizes revenue for sales at the time the natural gas, NGLs or crude oil are delivered at a fixed or determinable price.
Transaction Price Allocated to Remaining Performance Obligations
Devon applies the practical expedient exempting the disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For contracts with terms greater than one year, Devon applies the practical expedient exempting the disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under Devon’s contracts, each unit of product typically represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
6
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES FOR EAGLE FORD OIL AND GAS PROPERTIES
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
Disaggregation of Revenue
The following table presents revenue from contracts with customers that are disaggregated based on type of good (in thousands).
Six Months Ended June 30, Year Ended December 31,
2026202520252024
(unaudited)
(audited)
Oil$682,285 $396,707 $844,358 $961,653 
Gas44,473 33,810 67,781 45,433 
NGL60,371 43,063 84,604 100,599 
Operating revenues $787,129 $473,580 $996,743 $1,107,685 
Direct Operating Expenses
Direct operating expenses primarily include lease operating costs, gathering, processing and transportation costs and severance and ad valorem taxes. Lease operating costs include expenses such as labor, transportation, disposal, field office, vehicle, supervision, maintenance, tools and supplies and workover expenses.
The statements of revenues and direct operating expenses for the six months ended June 30, 2026 and June 30, 2025, are unaudited, but in the opinion of management include all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the results of the interim periods.
Note 2 – Commitments and Contingencies
Management is not aware of any additional legal, environmental or other commitments or contingencies that would have a material effect on the statements of revenues and direct operating expenses.
Note 3 – Subsequent Events
Management has evaluated subsequent events through September 30, 2026, the date the statements of revenues and direct operating expenses were available to be issued, and has concluded no events need to be reported during this period.
Note 4 – Supplemental Oil and Natural Gas Reserve Information (Unaudited)
Estimated Quantities of Proved Oil and Natural Gas Reserves
Estimated quantities of proved oil, natural gas and NGL reserves at December 31, 2025 and December 31, 2024, and changes in the reserves during the year for the Properties, are shown below.
These reserve estimates have been prepared in accordance with SEC regulations using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month.
7
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES FOR EAGLE FORD OIL AND GAS PROPERTIES
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
These estimates have been audited in accordance with generally accepted petroleum engineering and evaluation methods and procedures. All 2025 and 2024 reserves have been audited by DeGolyer and MacNaughton.
Oil (MBbls)Natural Gas (MMcf)NGL (MBbls)Total (MBoe)
December 31, 202357,104 95,245 16,563 89,541 
Revisions due to prices(358)(614)(116)(576)
Revisions other than price(294)436 869 648 
Extensions and discoveries6,198 10,625 1,782 9,751 
Production(12,741)(23,441)(4,071)(20,719)
December 31, 202449,909 82,251 15,027 78,645 
Revisions due to prices(2,334)(3,260)(603)(3,480)
Revisions other than price1,422 2,270 638 2,438 
Extensions and discoveries27,686 67,645 11,339 50,299 
Purchase of reserves23,192 59,334 10,245 43,326 
Production(13,254)(21,907)(3,519)(20,424)
Sale of reserves(106)(389)(62)(233)
December 31, 202586,515 185,944 33,065 150,571 
Proved developed reserves:
December 31, 202345,922 77,400 13,659 72,481 
December 31, 202443,603 77,428 14,148 70,655 
December 31, 202554,116 95,188 17,845 87,825 
Proved undeveloped reserves:
December 31, 202311,182 17,845 2,904 17,060 
December 31, 20246,306 4,823 879 7,990 
December 31, 202532,399 90,756 15,220 62,746 
Standardized Measure of Discounted Future Net Cash Flows
Information with respect to the standardized measure of discounted future net cash flows relating to proved reserves is summarized below. Future cash inflows, development and production costs are computed using the same assumptions for prices and costs that were used to estimate the Properties' proved reserves. As discussed in Note 1,
8
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES FOR EAGLE FORD OIL AND GAS PROPERTIES
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
the effects of income taxes are not included in the accompanying statements, and similarly are not included in the standardized measure presented here.
Year Ended December 31,
20252024
(in millions)
Future cash inflows (1)
$6,797 $4,279 
Future costs: (2)
Development(977)(342)
Production(2,633)(1,979)
Future net cash flow3,187 1,958 
10% discount to reflect timing of cash flows(1,037)(571)
Standardized measure of discounted future net cash flows$2,150 $1,387 
Representative prices: (1)
Natural gas (Mcf)$2.72 $2.10 
Oil (Bbl)$63.90 $75.32 
NGL (Bbl)$23.04 $23.04 
(1) In accordance with SEC regulations, reserves were estimated using the average price during the trailing 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month. The average price used to estimate reserves is held constant over the life of the reserves.
(2) Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions.
The following summarizes the principal sources of change in the standardized measure of discounted future net cash flows:
Year Ended December 31,
20252024
(in millions)
Beginning balance$1,387 $1,712 
Net changes in prices and production costs(254)(182)
Oil, gas and NGL sales, net of production costs(732)(865)
Changes in estimated future development costs(45)(94)
Extensions and discoveries, net of future development costs779 334 
Purchase of reserves (Asset Exchange)714 - 
Sales of reserves in place(3)- 
Revisions of quantity estimates56 55 
Previously estimated development costs incurred during the period143 290 
Accretion of discount and other105 137 
Ending balance$2,150 $1,387 
The data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the computations involve significant estimates and judgments. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the prices and costs utilized in the computation of reported amounts above. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.
9
Exhibit 99.5
UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS
Introduction
On October 8, 2026, Crescent Energy Company (“Crescent”) entered into a Purchase and Sale Agreement (the “Devon EF Assets Acquisition Agreement”) with Devon Energy Production Company, L.P. (“Devon”), a subsidiary of Devon Energy Corporation, pursuant to which Crescent agreed to acquire certain oil and natural gas properties located in the Eagle Ford (the “Devon EF Assets” and such transaction, the “Devon EF Assets Acquisition”) for aggregate cash consideration of approximately $4.2 billion, subject to customary purchase price adjustments. The Devon EF Assets Acquisition is expected to close in the fourth quarter of 2026 or early 2027, and the closing is subject to customary conditions, including, among other things, the expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976.
In connection with its entry into the Devon EF Assets Acquisition Agreement, Crescent obtained a debt commitment letter from JPMorgan Chase Bank, N.A. providing for a 364-day senior unsecured bridge loan facility in an aggregate principal amount of $2.0 billion, subject to the satisfaction of certain conditions (the “Bridge Commitment”). The pro forma financial statements assume that the cash consideration for the Devon EF Assets Acquisition is funded with (i) cash on hand of $247.6 million, (ii) borrowings of $2.0 billion under the Bridge Commitment (the “Bridge Borrowings”), and (iii) borrowings of $2.0 billion under the Crescent Revolving Credit Facility (as defined below) (such borrowings, the “Revolver Borrowings” and, together with the Bridge Borrowings and the Devon EF Assets Acquisition, the “Devon Transactions”). The pro forma financial statements do not give effect to any offering of debt or equity securities or other financing, the net cash proceeds of which would reduce the Bridge Commitment.
On December 15, 2025 (the “Vital Merger Closing Date”), Crescent completed its acquisition of Vital Energy, Inc. (“Vital”) pursuant to the Agreement and Plan of Merger, dated August 24, 2025 (such transaction, the “Vital Energy Merger”), and drew on Crescent’s senior secured reserve-based revolving credit agreement (the “Crescent Revolving Credit Facility”) to repay the outstanding borrowings under Vital’s senior secured credit facility (the “Vital Revolving Credit Facility”) immediately following the closing (the “RCF Draw”). The Vital Revolving Credit Facility was terminated upon repayment.
On January 31, 2025, Crescent completed its acquisition of all of the issued and outstanding securities of Ridgemar (Eagle Ford) LLC (“Ridgemar” and such transaction, the “Ridgemar Acquisition” and, together with the Vital Energy Merger, the “2025 Acquisitions”).
The unaudited pro forma condensed combined financial statements (the “pro forma financial statements”) have been prepared from the historical consolidated financial statements of Crescent, the historical statements of revenues and direct operating expenses of the Devon EF Assets and, for the year ended December 31, 2025, the historical financial information of Vital and Ridgemar for the periods prior to their respective acquisitions, adjusted to give effect to the Devon Transactions and, for the year ended December 31, 2025, the 2025 Acquisitions and the RCF Draw (collectively with the Devon Transactions, the “Pro Forma Transactions”). The unaudited pro forma condensed combined balance sheet as of June 30, 2026 (the “pro forma balance sheet”) gives effect to the Devon Transactions as if they had occurred on June 30, 2026. The unaudited pro forma condensed combined statements of operations for the six months ended June 30, 2026 and for the year ended December 31, 2025 (the “pro forma statements of operations”) give effect to the Pro Forma Transactions as if each had occurred on January 1, 2025.
The pro forma balance sheet as of June 30, 2026 and the pro forma statement of operations for the six months ended June 30, 2026 reflect no adjustments for the 2025 Acquisitions or the RCF Draw, as those transactions are already reflected in Crescent’s historical balance sheet and statement of operations for such periods. The pro forma financial statements contain certain reclassification adjustments to conform the historical financial statement presentation of the Devon EF Assets, Vital and Ridgemar with Crescent’s historical financial statement presentation.
The historical financial information of the Devon EF Assets consists of statements of revenues and direct operating expenses, which do not include general and administrative expense, the effects of derivative transactions, interest income or expense, depreciation, depletion and amortization, any provision for income tax expense and other income and expense items not directly associated with the Devon EF Assets. Historical financial statements


reflecting financial position, results of operations and cash flows are not presented for the Devon EF Assets, as such information is not readily available and not meaningful to the Devon EF Assets. Accordingly, the pro forma statements of operations are not indicative of the results of operations of the Devon EF Assets going forward, because they necessarily exclude various operating expenses. No historical balance sheet of the Devon EF Assets is presented. The pro forma balance sheet reflects the Devon EF Assets Acquisition through transaction accounting adjustments based on the preliminary purchase price allocation described in Note 2.
The following pro forma financial statements are based on, and should be read in conjunction with:
•the audited consolidated financial statements of Crescent for the year ended December 31, 2025 and the unaudited condensed consolidated financial statements of Crescent as of and for the six months ended June 30, 2026, and the related notes thereto;
•the audited statements of revenues and direct operating expenses of the Devon EF Assets for the years ended December 31, 2025 and 2024 and the unaudited statements of revenues and direct operating expenses of the Devon EF Assets for the six months ended June 30, 2026 and 2025, and the related notes thereto, included as Exhibit 99.4 to this Current Report on Form 8-K;
•the unaudited condensed consolidated financial statements of Vital for the nine months ended September 30, 2025, and the related notes thereto, included as Exhibit 99.3 to this Current Report on Form 8-K; and
•the sections entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Risk Factors” and other cautionary statements included in Crescent’s Annual Report on Form 10-K for the year ended December 31, 2025 and Quarterly Report on Form 10-Q for the quarter ended June 30, 2026.
The pro forma financial statements were derived by making certain transaction accounting adjustments to the historical financial statements noted above. The adjustments are based on currently available information and certain estimates and assumptions. Therefore, the actual impact of the Pro Forma Transactions may differ from the adjustments made to the pro forma financial statements. However, Crescent’s management believes that the assumptions provide a reasonable basis for presenting the significant effects for the periods presented as if the Pro Forma Transactions had been consummated earlier, and that all adjustments necessary to fairly present the pro forma financial statements have been made.
As of the date of this Current Report on Form 8-K, Crescent has not completed the detailed valuation study necessary to arrive at the required final estimates of the fair value of the Devon EF Assets to be acquired and the liabilities to be assumed and the related allocation of purchase price. A final determination of the fair value of the Devon EF Assets and the related liabilities will be based on the assets acquired and liabilities assumed as of the closing date of the Devon EF Assets Acquisition (the “Devon Closing Date”) and, therefore, cannot be made prior to the completion of the Devon EF Assets Acquisition. As a result of the foregoing, the pro forma adjustments are preliminary and are subject to change as additional information becomes available or as additional analysis is performed.
The preliminary pro forma adjustments have been made solely for the purpose of providing the unaudited pro forma financial statements presented below. Crescent estimated the fair value of the Devon EF Assets and the related liabilities based on preliminary valuation studies, due diligence and information provided by Devon. Any increases or decreases in the fair value of assets acquired and liabilities assumed upon completion of the final valuations will result in adjustments to the pro forma financial statements. The final purchase price allocation may be materially different than that reflected in the preliminary pro forma purchase price allocation presented herein.
The pro forma financial statements and related notes are presented for illustrative purposes only and should not be relied upon as an indication of the financial position or operating results that Crescent would have achieved if the Devon EF Assets Acquisition Agreement had been entered into and the Pro Forma Transactions had taken place on the assumed dates. The pro forma financial statements do not reflect future events that may occur after the consummation of the Devon EF Assets Acquisition, including, but not limited to, the anticipated realization of ongoing savings from potential operating efficiencies, asset dispositions, cost savings, or economies of scale that


Crescent may achieve with respect to the combined operations. As a result, future results may vary significantly from the results reflected in the pro forma financial statements and should not be relied on as an indication of the future results of Crescent.

Unaudited Pro Forma Condensed Combined Balance Sheet
As of June 30, 2026
(in thousands)
Crescent
(Historical)		Transaction Accounting AdjustmentsCrescent Pro Forma Combined
ASSETS
Current assets:
Cash and cash equivalents$264,882 $(247,600)(a)$17,282 
Restricted cash5,467 — 5,467 
Accounts receivable, net664,936 — 664,936 
Accounts receivable – affiliates3,899 — 3,899 
Derivative assets – current53,759 — 53,759 
Prepaid expenses49,642 — 49,642 
Other current assets60,027 — 60,027 
Total current assets1,102,612 (247,600)855,012 
Property, plant and equipment:
Oil and natural gas properties at cost, successful efforts method
Proved14,132,507 3,502,890 (b)17,635,397 
Unproved567,174 849,150 (b)1,416,324 
Oil and natural gas properties at cost, successful efforts method14,699,681 4,352,040 19,051,721 
Field and other property and equipment, at cost177,134 — 177,134 
Total property, plant and equipment14,876,815 4,352,040 19,228,855 
Less: accumulated depreciation, depletion, amortization and impairment(4,245,505)— (4,245,505)
Property, plant and equipment, net10,631,310 4,352,040 14,983,350 
Derivative assets – noncurrent22,024 — 22,024 
Investments in equity affiliates9,149 — 9,149 
Deferred tax asset73,086 — 73,086 
Other assets170,195 — 170,195 
TOTAL ASSETS$12,008,376 $4,104,440 $16,112,816 
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued liabilities$977,199 $56,700 
(c)
$1,033,899 
Accounts payable – affiliates20,814 — 20,814 
Derivative liabilities – current28,345 — 28,345 
Financing lease obligations – current4,225 — 4,225 
Short-term debt— 1,989,000 (a)1,989,000 
Other current liabilities136,752 — 136,752 
Total current liabilities1,167,335 2,045,700 3,213,035 
Long-term debt5,166,022 1,983,400 (a)7,149,422 
Derivative liabilities – noncurrent9,854 — 9,854 
Asset retirement obligations379,933 75,340 (b)455,273 
Deferred tax liability15,127 — 15,127 
Financing lease obligations – noncurrent1,435 — 1,435 
Other liabilities109,081 — 109,081 
Total liabilities6,848,787 4,104,440 10,953,227 
Equity:
Class A common stock33 — 33 
Class B common stock— — — 
Preferred stock— — — 
Treasury stock, at cost(72,441)— (72,441)
Additional paid-in capital5,191,073 — 5,191,073 
Retained earnings (accumulated deficit)33,287 — 33,287 
Noncontrolling interests7,637 — 7,637 
Total equity5,159,589 — 5,159,589 
TOTAL LIABILITIES AND EQUITY$12,008,376 $4,104,440 $16,112,816 
The accompanying notes are an integral part of these unaudited pro forma condensed combined financial statements.

Unaudited Pro Forma Condensed Combined Statement of Operations
For the Six Months Ended June 30, 2026
(in thousands, except per share data)
Crescent
(Historical)		Devon EF Assets (Historical)Transaction Accounting AdjustmentsCrescent Pro Forma Combined
Revenues:
Oil$2,120,146 $— $682,285 (a)$2,802,431 
Natural gas192,141 — 44,473 (a)236,614 
Natural gas liquids254,478 — 60,371 (a)314,849 
Midstream and other11,019 — — 11,019 
Operating revenues— 787,129 (787,129)(a)— 
Total revenues
2,577,784 787,129 — 3,364,913 
Expenses:
Lease and asset operating expense441,278 — 93,453 (a)534,731 
Workover expense63,245 — — 63,245 
Gathering, processing and transportation196,554 — 29,748 (a)226,302 
Production and other taxes124,707 — 39,955 (a)164,662 
Direct operating expenses— 163,156 (163,156)(a)— 
Depreciation, depletion and amortization712,129 — 263,934 (b)976,063 
Impairment of oil and natural gas properties— — — — 
Exploration expense6,885 — — 6,885 
Midstream and other operating expense10,904 — — 10,904 
General and administrative expense124,294 — — 124,294 
Gain on sale of assets(10,690)— — (10,690)
Total expenses
1,669,306 163,156 263,934 2,096,396 
Income (loss) from operations
908,478 623,973 (263,934)1,268,517 
Other income (expense):
Loss on derivatives(524,708)— — (524,708)
Interest expense(204,397)— (132,760)(c)(337,157)
Loss from extinguishment of debt(17,397)— — (17,397)
Other income (expense)144 — — 144 
Income (loss) from equity affiliates
56 — — 56 
Total other income (expense)
(746,302)— (132,760)(879,062)
Income (loss) before taxes162,176 623,973 (396,694)389,455 
Income tax expense(87,648)— (50,001)(d)(137,649)
Net income (loss)
74,528 623,973 (446,695)251,806 
Less: net income attributable to noncontrolling interests(1,610)— — (1,610)
Net income (loss) attributable to Crescent Energy
$72,918 $623,973 $(446,695)$250,196 
Net income (loss) per share:
Class A common stock – basic$0.22 $0.76 (g)
Class A common stock – diluted$0.21 $0.69 (g)
Class B common stock – basic and diluted$— $— 
Weighted average shares outstanding:
Class A common stock – basic329,283 329,283 
Class A common stock – diluted366,832 366,832 
Class B common stock – basic and diluted— — 
The accompanying notes are an integral part of these unaudited pro forma condensed combined financial statements.

Unaudited Pro Forma Condensed Combined Statement of Operations
For the Year Ended December 31, 2025
(in thousands, except per share data)
Crescent
(Historical)		2025 Acquisitions Adjustments
(See Note 3)		Crescent Pro Forma for 2025 AcquisitionsDevon EF Assets
(Historical)		Transaction Accounting AdjustmentsCrescent Pro Forma Combined
Revenues:
Oil$2,372,726 $1,505,277 $3,878,003 $— $844,358 (a)$4,722,361 
Natural gas673,540 39,072 712,612 — 67,781 (a)780,393 
Natural gas liquids390,629 189,878 580,507 — 84,604 (a)665,111 
Midstream and other142,887 5,158 148,045 — — 148,045 
Operating revenues— — — 996,743 (996,743)(a)— 
Total revenues
3,579,782 1,739,385 5,319,167 996,743 — 6,315,910 
Expenses:
Lease and asset operating expense767,814 360,862 1,128,676 — 163,726 (a)1,292,402 
Workover expense74,537 63,829 138,366 — — 138,366 
Gathering, processing and transportation408,920 65,403 474,323 — 43,541 (a)517,864 
Production and other taxes219,416 101,160 320,576 — 57,686 (a)378,262 
Direct operating expenses— — — 264,953 (264,953)(a)— 
Depreciation, depletion and amortization1,166,902 284,552 1,451,454 — 422,135 (b)1,873,589 
Impairment expense254,551 1,005,242 1,259,793 — — 1,259,793 
Exploration expense16,795 2,257 19,052 — — 19,052 
Midstream and other operating expense116,945 10,850 127,795 — — 127,795 
General and administrative expense472,160 165,250 637,410 — — 637,410 
Gain on sale of assets(147,537)(2,416)(149,953)— — (149,953)
Total expenses
3,350,503 2,056,989 5,407,492 264,953 422,135 6,094,580 
Income (loss) from operations
229,279 (317,604)(88,325)731,790 (422,135)221,330 
Other income (expense):
Gain on derivatives302,901 273,564 576,465 — — 576,465 
Interest expense(298,432)(196,218)(494,650)— (276,519)(c)(771,169)
Loss from extinguishment of debt(29,248)— (29,248)— — (29,248)
Other income (expense)(5,018)3,142 (1,876)— — (1,876)
Income (loss) from equity affiliates2,188 (345)1,843 — — 1,843 
Total other income (expense)
(27,609)80,143 52,534 — (276,519)(223,985)
Income (loss) before taxes201,670 (237,461)(35,791)731,790 (698,654)(2,655)
Income tax expense(34,504)(329,153)(363,657)— (7,290)(d)(370,947)
Net income (loss)
167,166 (566,614)(399,448)731,790 (705,944)(373,602)
Less: net income attributable to noncontrolling interests(20,210)— (20,210)— — (20,210)
Less: net (income) loss attributable to redeemable noncontrolling interests(14,050)11,651 (2,399)— (1,673)(e)(4,072)
Net income (loss) attributable to Crescent Energy
$132,906 $(554,963)$(422,057)$731,790 $(707,617)$(397,884)
Net income (loss) per share:
Class A common stock – basic$0.55 $(1.35)(f)$(1.27)(g)
Class A common stock – diluted$0.54 $(1.35)(f)$(1.27)(g)
Class B common stock – basic and diluted$— $— $— 
Weighted average shares outstanding:
Class A common stock – basic242,060 312,266 (f)312,266 (g)
Class A common stock – diluted245,058 312,266 (f)312,266 (g)
Class B common stock – basic and diluted16,609 16,609 16,609 
The accompanying notes are an integral part of these unaudited pro forma condensed combined financial statements.

Notes to unaudited pro forma condensed combined financial statements
NOTE 1 – Basis of pro forma presentation
The pro forma financial statements have been derived from the historical consolidated financial statements of Crescent, the historical statements of revenues and direct operating expenses of the Devon EF Assets and, for the year ended December 31, 2025, the historical financial information of Vital for the period from January 1, 2025 through December 14, 2025 and of Ridgemar for the period from January 1, 2025 through January 30, 2025. The pro forma balance sheet as of June 30, 2026 gives effect to the Devon Transactions as if they had occurred on June 30, 2026. The pro forma statement of operations for the year ended December 31, 2025 gives effect to the Pro Forma Transactions, and the pro forma statement of operations for the six months ended June 30, 2026 gives effect to the Devon Transactions, in each case as if they had occurred on January 1, 2025. The 2025 Acquisitions and the RCF Draw are reflected in Crescent’s historical balance sheet as of June 30, 2026 and statement of operations for the six months then ended.
The pro forma financial statements reflect pro forma adjustments that are based on available information and certain assumptions that management believes are reasonable. However, actual results may differ from those reflected in these pro forma financial statements. In management’s opinion, all adjustments known to date that are necessary to fairly present the pro forma information have been made. The pro forma financial statements do not purport to represent what the combined entity’s financial position or results of operations would have been if the Pro Forma Transactions had actually occurred on the dates indicated above, nor are they indicative of Crescent’s future financial position or results of operations.
These pro forma financial statements should be read in conjunction with the historical financial statements, and related notes thereto, of Crescent, Vital and Ridgemar, and the historical statements of revenues and direct operating expenses, and related notes thereto, of the Devon EF Assets, for the periods presented.
NOTE 2 – Pro forma acquisition accounting
The Devon EF Assets Acquisition is expected to be accounted for as an asset acquisition. The allocation of the preliminary estimated purchase price is based upon management’s estimates of and assumptions related to the fair value of assets to be acquired and liabilities to be assumed as of June 30, 2026 using currently available information. Because the pro forma financial statements have been prepared based on these preliminary estimates, the final purchase price allocation and the resulting effect on Crescent’s financial position and results of operations may differ significantly from the pro forma amounts included in this Current Report on Form 8-K. Crescent expects to finalize its allocation of the purchase price as soon as practicable after completion of the Devon EF Assets Acquisition. The cost of the Devon EF Assets Acquisition, including transaction costs, is allocated to the assets to be acquired based on their relative fair values, and no goodwill is recognized.
The preliminary purchase price allocation is subject to change as a result of several factors, including but not limited to:
•changes in the estimated fair value of the Devon EF Assets to be acquired and liabilities to be assumed as of the Devon Closing Date, which could result from changes in future oil and natural gas commodity prices, reserve estimates, interest rates, and other factors; and
•purchase price adjustments under the Devon EF Assets Acquisition Agreement and the final amount of transaction costs.
The preliminary determination of consideration transferred and the purchase price allocation to assets to be acquired and liabilities to be assumed is as follows (in thousands):


Devon EF Assets Acquisition
Consideration transferred:
Cash consideration$4,220,000 
Transaction costs capitalized56,700 
Total$4,276,700 
Assets acquired and liabilities assumed:
Oil and natural gas properties - proved3,502,890 
Oil and natural gas properties - unproved849,150 
Asset retirement obligations(75,340)
Total assets acquired and liabilities assumed$4,276,700 
2025 Acquisitions
The Vital Energy Merger was accounted for using the acquisition method of accounting for business combinations in accordance with ASC 805 with Crescent considered to be the accounting acquirer. The allocation of the purchase price for Vital is preliminary. Certain data necessary to complete the purchase price allocation is not yet available, including final tax returns that provide the underlying tax basis of Vital’s assets and liabilities, and Crescent expects to complete the purchase price allocation during the 12-month period following the Vital Merger Closing Date. During the six months ended June 30, 2026, Crescent adjusted the preliminary purchase price allocation for the Vital Energy Merger to reflect certain post-closing adjustments, which are reflected in the table below. The assets acquired and liabilities assumed in the Vital Energy Merger are reflected in Crescent’s historical balance sheet as of June 30, 2026.
The preliminary purchase price allocation for the Vital Energy Merger is subject to change as a result of several factors, including but not limited to:
•changes in the estimated fair value of Vital’s assets acquired and liabilities assumed as of the Vital Merger Closing Date;
•the tax basis of Vital’s assets and liabilities as of the Vital Merger Closing Date; and
•certain of the factors described in “Risk Factors” included in Crescent’s Annual Report on Form 10-K for the year ended December 31, 2025 and Quarterly Report on Form 10-Q for the quarter ended June 30, 2026.


The Ridgemar Acquisition was accounted for as an asset acquisition. The allocation of the purchase price for Ridgemar has been completed.
The determination of consideration transferred and the purchase price allocation to assets acquired and liabilities assumed for the 2025 Acquisitions, as presented in Crescent’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2026, is as follows (in thousands):
Vital Energy MergerRidgemar Acquisition
Consideration transferred:
Cash consideration:
Cash$— $807,247 
Settlement of Equity Awards in cash3,693 — 
Equity consideration:
Fair value of Class A Common Stock issued640,982 82,145 
Settlement of Equity Awards in Class A Common Stock7,557 — 
Fair value of contingent earn-out consideration— 51,746 
Transaction costs capitalized— 18,484 
Total$652,232 $959,622 
Assets acquired and liabilities assumed:
Cash and cash equivalents$122,923 $— 
Accounts receivable, net276,882 1,150 
Derivative assets – current184,247 — 
Prepaid expenses25,559 — 
Oil and natural gas properties - proved2,220,703 988,758 
Oil and natural gas properties - unproved137,846 — 
Field and other property and equipment50,156 3,240 
Derivative assets – noncurrent2,471 — 
Deferred tax asset695,291 — 
Other assets62,847 — 
Accounts payable and accrued liabilities(423,031)(9,565)
Other current liabilities(39,046)(573)
Long-term debt(2,490,578)— 
Derivative liabilities – noncurrent(7,329)— 
Asset retirement obligations(127,821)(22,855)
Other liabilities(38,888)(533)
Net assets acquired$652,232 $959,622 
NOTE 3 – 2025 Acquisitions Adjustments
Pro forma statement of operations for the year ended December 31, 2025
The column “2025 Acquisitions Adjustments” in the pro forma statement of operations for the year ended December 31, 2025 reflects the historical results of Vital for the period from January 1, 2025 through December 14, 2025 and of Ridgemar for the period from January 1, 2025 through January 30, 2025, together with the transaction


accounting adjustments for the 2025 Acquisitions and the financing adjustments for the RCF Draw. A reconciliation of the amounts presented as “2025 Acquisitions Adjustments” is as follows (in thousands):
Vital As Adjusted
(See Note 4)		Ridgemar
(Historical)		Transaction Accounting AdjustmentsFinancing Adjustments2025 Acquisitions Adjustments
Revenues:
Oil$1,467,340 $37,937 $— $— $1,505,277 
Natural gas38,126 946 — — 39,072 
Natural gas liquids188,122 1,756 — — 189,878 
Midstream and other5,158 — — — 5,158 
Total revenues
1,698,746 40,639 — — 1,739,385 
Expenses:
Lease and asset operating expense357,010 3,852 — — 360,862 
Workover expense63,404 425 — — 63,829 
Gathering, processing and transportation63,947 1,456 — — 65,403 
Production and other taxes99,549 1,611 — — 101,160 
Depreciation, depletion and amortization715,697 — (431,145)(a)— 284,552 
Impairment expense1,005,242 — — — 1,005,242 
Exploration expense— — 2,257 (b)— 2,257 
Midstream and other operating expense10,850 — — — 10,850 
General and administrative expense135,878 — 22,622 (b)— 165,250 
6,750 (c)
Gain on sale of assets(2,416)— — — (2,416)
Total expenses
2,449,161 7,344 (399,516)— 2,056,989 
Income (loss) from operations
(750,415)33,295 399,516 — (317,604)
Other income (expense):
Gain on derivatives273,564 — — — 273,564 
Interest expense(197,139)— — 921 (f)(196,218)
Loss from extinguishment of debt— — — — — 
Other income (expense)3,142 — — — 3,142 
Income (loss) from equity affiliates
(345)— — — (345)
Total other income (expense)
79,222 — — 921 80,143 
Income (loss) before taxes(671,193)33,295 399,516 921 (237,461)
Income tax expense(235,032)— (93,737)(d)(384)(d)(329,153)
Net income (loss)
(906,225)33,295 305,779 537 (566,614)
Less: net (income) loss attributable to redeemable noncontrolling interests— — 11,698 (e)(47)(e)11,651 
Net income (loss) attributable to Crescent Energy
$(906,225)$33,295 $317,477 $490 $(554,963)
Transaction Accounting Adjustments
(a)Reflects pro forma depletion expense calculated in accordance with the successful efforts method of accounting for oil and gas properties. For the Vital Energy Merger, the adjustment also reflects the increase in accretion expense related to the higher asset retirement obligation liability which was adjusted to reflect Crescent’s internal estimates, discount rate, and useful life estimate. For the Ridgemar Acquisition, the adjustment reflects pro forma depletion expense and accretion expense for the period from January 1, 2025 through January 30, 2025.
(b)Reflects adjustments to general and administrative expense and exploration expense related to costs capitalized by Vital under the full cost method of accounting for oil and gas properties that are expensed on a pro forma basis to conform to Crescent’s accounting under the successful efforts method of accounting for oil and gas properties.
(c)Reflects the impact on general and administrative expense related to increases in Crescent's Management Fee related to the issuance of additional shares of Crescent Class A Common Stock as consideration in the Vital Energy Merger.


(d)Reflects the income tax effect of the pro forma adjustments presented.
(e)Reflects the impact of the allocation of net income attributable to redeemable noncontrolling interests related to the change in Crescent’s ownership of Crescent Energy OpCo LLC resulting from the issuance of 73.3 million shares of Crescent Class A Common Stock as part of the Vital Energy Merger, and the allocation to redeemable noncontrolling interests of Ridgemar’s historical results and the pro forma adjustments for the Ridgemar Acquisition.
Financing Adjustments
(f)Reflects the pro forma impact of the RCF Draw to repay outstanding amounts borrowed under the Vital Revolving Credit Facility, and the pro forma interest expense related to borrowings of $655.0 million under the Crescent Revolving Credit Facility to fund a portion of the cash consideration for the Ridgemar Acquisition for the period from January 1, 2025 through January 30, 2025.


NOTE 4 – Adjustments to Vital’s historical statement of operations
Pro forma statement of operations reclassification adjustments for the year ended December 31, 2025
Certain reclassification adjustments were made to Vital’s historical statement of operations in order to conform with Crescent’s financial statement presentation. A reconciliation of amounts derived and presented as “Vital As Adjusted” in Note 3 is as follows (in thousands, except per share data):
Vital
(Historical)(1)
Vital
(Historical)(2)
Vital
Reclassification Adjustments		Vital As Adjusted
Revenues:
Oil$— $— $1,467,340 $1,467,340 
Oil sales
1,155,448 311,892 (1,467,340)— 
Natural gas— — 38,126 38,126 
Natural gas sales47,175 (9,049)(38,126)— 
Natural gas liquids— — 188,122 188,122 
NGL sales155,714 32,408 (188,122)— 
Midstream and other— — 5,158 5,158 
Other operating revenues4,296 862 (5,158)— 
Total revenues
1,362,633 336,113 — 1,698,746 
Expenses:
Lease and asset operating expense— — 357,010 357,010 
Lease operating expense325,494 94,920 (357,010)— 
(63,404)
Workover expense— — 63,404 63,404 
Gathering, processing and transportation— — 63,947 63,947 
Oil transportation and marketing expenses31,296 7,855 (39,151)— 
Gas gathering, processing and transportation expenses18,910 5,886 (24,796)— 
Production and other taxes— — 99,549 99,549 
Production and ad valorem taxes80,106 19,443 (99,549)— 
Depreciation, depletion and amortization— — 711,908 715,697 
3,789 
Depletion, depreciation and amortization556,840 155,068 (711,908)— 
Impairment expense1,005,242 — — 1,005,242 
Midstream and other operating expense— — 10,850 10,850 
Other operating expenses, net10,456 4,528 (10,850)— 
(3,789)
(345)
General and administrative expense— — 135,878 135,878 
General and administrative71,517 59,734 (131,251)— 
Organizational restructuring expenses4,627 — (4,627)— 
Gain on sale of assets— — (2,416)(2,416)
Total expenses
2,104,488 347,434 (2,761)2,449,161 
Gain (loss) on disposal of assets, net2,050 366 (2,416)— 
Income (loss) from operations
(739,805)(10,955)345 (750,415)
Other income (expense):
Gain on derivatives— — 273,564 273,564 
Gain (loss) on derivatives, net169,233 104,331 (273,564)— 
Interest expense(150,228)(46,911)— (197,139)
Loss from extinguishment of debt— — — — 
Other income (expense)— — 3,142 3,142 
Other income (expense), net2,215 927 (3,142)— 
Income (loss) from equity affiliates
— — (345)(345)
Total other income (expense)
21,220 58,347 (345)79,222 


Income (loss) before taxes(718,585)47,392 — (671,193)
Income tax benefit (expense)(236,346)1,314 — (235,032)
Net income (loss)
$(954,931)$48,706 $— $(906,225)
Net income (loss) per share:
Basic$(25.32)
Diluted$(25.32)
Weighted average common shares outstanding:
Basic37,714 
Diluted37,714 
______________
(1)Reflects the historical operations of Vital for the nine months ended September 30, 2025.
(2)Reflects the historical operations of Vital for the period from October 1, 2025 through December 14, 2025.
NOTE 5 – Adjustments to the pro forma financial statements
The pro forma financial statements have been prepared to illustrate the effects of the Pro Forma Transactions and have been prepared for informational purposes only.
The preceding pro forma financial statements have been prepared in accordance with Article 11 of Regulation S-X which requires the presentation of adjustments to account for the pro forma transactions (“Transaction Accounting Adjustments”) and allows for supplemental disclosure of the reasonably estimable synergies and other transaction effects that have occurred or are reasonably expected to occur (“Management Adjustments”). Management has elected not to present Management Adjustments.
Pro forma balance sheet adjustments as of June 30, 2026
The adjustments included in the pro forma balance sheet as of June 30, 2026 are as follows:
Transaction Accounting Adjustments
(a)Reflects the funding of the cash consideration for the Devon EF Assets Acquisition and related debt issuance costs with (i) cash on hand of $247.6 million, (ii) borrowings of $2.0 billion under the Bridge Commitment, net of debt issuance costs of $11.0 million, presented as short-term debt because the Bridge Borrowings mature 364 days after the closing of the Devon EF Assets Acquisition, and (iii) borrowings of $2.0 billion under the Crescent Revolving Credit Facility, presented as long-term debt.
(b)Reflects the recognition of the oil and natural gas properties to be acquired at their preliminary allocated cost and the asset retirement obligations to be assumed in the Devon EF Assets Acquisition. See Note 2 for further details.
(c)Reflects the accrual of estimated transaction costs of $56.7 million directly related to the Devon EF Assets Acquisition, which are capitalized as part of the cost of the oil and natural gas properties to be acquired. Estimated transaction costs are based on preliminary estimates, and the final amounts and the resulting effect on Crescent's financial position may differ significantly. These incremental costs are not yet reflected in the historical consolidated balance sheet of Crescent as of June 30, 2026. The estimated incremental transaction costs are reflected in the pro forma balance sheet as an increase to accounts payable and accrued liabilities.
Pro forma statements of operations adjustments for the six months ended June 30, 2026 and for the year ended December 31, 2025
The adjustments included in the pro forma statements of operations for the six months ended June 30, 2026 and for the year ended December 31, 2025 are as follows:
Transaction Accounting Adjustments
(a)Reflects reclassification adjustments made to the Devon EF Assets’ historical statements of revenues and direct operating expenses in order to conform with Crescent’s financial statement presentation. Operating revenues


were reclassified to oil, natural gas and natural gas liquids revenues, and direct operating expenses were reclassified to lease and asset operating expense, gathering, processing and transportation and production and other taxes.
(b)Reflects pro forma depletion expense on the Devon EF Assets calculated in accordance with the successful efforts method of accounting for oil and gas properties and accretion expense on the asset retirement obligations assumed.
(c)Reflects pro forma interest expense on the Bridge Borrowings at an assumed interest rate of 7.41%, based on Term SOFR as of September 30, 2026 plus the initial margin of 3.50% applied to each period presented, and on the Revolver Borrowings at an assumed interest rate of 5.91%. Debt issuance costs of $11.0 million related to the short-term Bridge Borrowings were amortized over its term and recognized within pro forma interest expense for the year ended December 31, 2025. A change of 0.125% in the assumed interest rates would change pro forma interest expense by approximately $5.0 million for the year ended December 31, 2025 and $2.5 million for the six months ended June 30, 2026.
(d)Reflects the income tax effect of the historical revenues and direct operating expenses of the Devon EF Assets and of the pro forma adjustments presented. The tax rate applied was the estimated combined federal and state statutory rate of 22.0%. The effective rate of Crescent in the future could be significantly different (either higher or lower) depending on a variety of factors.
(e)Reflects the allocation to redeemable noncontrolling interests of the net income effect of the Devon EF Assets’ historical revenues and direct operating expenses and of the pro forma adjustments for the portion of the year ended December 31, 2025 prior to the elimination of Crescent’s Up-C structure in April 2025, based on the pro forma ownership of Crescent Energy OpCo LLC held by the redeemable noncontrolling interest holders during that period. No redeemable noncontrolling interests remain following the elimination of the Up-C structure.
(f)Reflects the impact to the allocation of net income attributable to Crescent and the computation of basic and diluted net income (loss) per share for the issuance of 73.3 million shares of Crescent Class A Common Stock as part of the Vital Energy Merger.
(g)Reflects the impact of the pro forma adjustments on the computation of basic and diluted net income (loss) per share. No shares of Crescent Class A Common Stock are issued in the Devon Transactions.
NOTE 6 – Supplemental unaudited pro forma oil and natural gas reserves information
Oil and natural gas reserves
The following tables present the estimated unaudited pro forma net proved developed and proved undeveloped oil, natural gas, and NGL reserves information as of December 31, 2025 for Crescent’s consolidated operations, along with a summary of changes in quantities of net remaining proved reserves for the year ended December 31, 2025. The disclosures below are derived from the “Oil and natural gas reserves” for the year ended December 31, 2025 included within Crescent’s Annual Report on Form 10-K and the supplemental oil and gas information of the Devon EF Assets included in Exhibit 99.4 to this Current Report on Form 8-K. The estimates below are in certain instances presented on a “barrels of oil equivalent” or “Boe” basis. To determine Boe in the following tables, natural gas is converted to a crude oil equivalent at the ratio of six Mcf of natural gas to one barrel of crude oil equivalent.
The unaudited pro forma oil and natural gas reserves information is not necessarily indicative of the results that might have occurred had the Pro Forma Transactions been completed on January 1, 2025 and is not intended to be a projection of future results. Future results may vary significantly from the results reflected because of various factors, including those discussed in “Risk Factors” included in Crescent’s Annual Report on Form 10-K.
The unaudited pro forma net proved developed and proved undeveloped oil, natural gas, and NGL reserves as of December 31, 2024 and 2025 and the changes in the pro forma quantities of net remaining proved reserves for the year ended December 31, 2025 are as follows:


Oil and Condensate (MBbls)
Crescent
(Historical)		2025 Acquisitions AdjustmentsCrescent Pro Forma for 2025 AcquisitionsDevon EF Assets (Historical)Crescent Pro Forma Combined
Proved Developed and Undeveloped Reserves as of:
December 31, 2024297,690243,346541,03649,909590,945
Revisions of previous estimates(59,053)(50,992)(110,045)(912)(110,957)
Extensions, discoveries, and other additions20,23212,71932,95127,68660,637
Sales of reserves in place(43,427)(733)(44,160)(106)(44,266)
Purchases of reserves in place182,392(180,469)1,92323,19225,115
Production(38,139)(23,871)(62,010)(13,254)(75,264)
December 31, 2025359,695—359,69586,515446,210
Proved Developed Reserves as of:
December 31, 2024193,611156,941350,55243,603394,155
December 31, 2025275,734—275,73454,116329,850
Proved Undeveloped Reserves as of:
December 31, 2024104,07986,405190,4846,306196,790
December 31, 202583,961—83,96132,399116,360
Natural Gas (MMcf)
Crescent
(Historical)		2025 Acquisitions AdjustmentsCrescent Pro Forma for 2025 AcquisitionsDevon EF Assets (Historical)Crescent Pro Forma Combined
Proved Developed and Undeveloped Reserves as of:
December 31, 20241,595,059861,9822,457,04182,2512,539,292
Revisions of previous estimates40,084(80,825)(40,741)(990)(41,731)
Extensions, discoveries, and other additions436,51335,705472,21867,645539,863
Sales of reserves in place(291,673)(16,020)(307,693)(389)(308,082)
Purchases of reserves in place735,054(719,517)15,53759,33474,871
Production(236,978)(81,325)(318,303)(21,907)(340,210)
December 31, 20252,278,059—2,278,059185,9442,464,003
Proved Developed Reserves as of:
December 31, 20241,342,718628,8961,971,61477,4282,049,042
December 31, 20251,819,476—1,819,47695,1881,914,664
Proved Undeveloped Reserves as of:
December 31, 2024252,341233,086485,4274,823490,250
December 31, 2025458,583—458,58390,756549,339


Natural Gas Liquids (MBbls)
Crescent
(Historical)		2025 Acquisitions AdjustmentsCrescent Pro Forma for 2025 AcquisitionsDevon EF Assets (Historical)Crescent Pro Forma Combined
Proved Developed and Undeveloped Reserves as of:
December 31, 2024145,716151,703297,41915,027312,446
Revisions of previous estimates(10,331)(12,841)(23,172)35(23,137)
Extensions, discoveries, and other additions9,4386,56015,99811,33927,337
Sales of reserves in place(21,288)(2,254)(23,542)(62)(23,604)
Purchases of reserves in place129,993(128,665)1,32810,24511,573
Production(17,382)(14,503)(31,885)(3,519)(35,404)
December 31, 2025236,146 —236,14633,065269,211
Proved Developed Reserves as of:
December 31, 2024109,223108,609217,83214,148231,980
December 31, 2025197,366—197,36617,845215,211
Proved Undeveloped Reserves as of:
December 31, 202436,49343,09479,58787980,466
December 31, 202538,780—38,78015,22054,000
Total (MBoe)
Crescent
(Historical)		2025 Acquisitions AdjustmentsCrescent Pro Forma for 2025 AcquisitionsDevon EF Assets (Historical)Crescent Pro Forma Combined
Proved Developed and Undeveloped Reserves as of:
December 31, 2024709,251538,7131,247,96478,6451,326,609
Revisions of previous estimates(62,706)(77,304)(140,010)(1,042)(141,052)
Extensions, discoveries, and other additions102,42325,230127,65350,299177,952
Sales of reserves in place(113,327)(5,657)(118,984)(233)(119,217)
Purchases of reserves in place434,894(429,054)5,84043,32649,166
Production(95,017)(51,928)(146,945)(20,424)(167,369)
December 31, 2025975,518 —975,518150,5711,126,089
Proved Developed Reserves as of:
December 31, 2024526,622370,366896,98870,655967,643
December 31, 2025776,346—776,34687,825864,171
Proved Undeveloped Reserves as of:
December 31, 2024182,629168,347350,9767,990358,966
December 31, 2025199,172—199,17262,746261,918
Standardized measure of discounted future net cash flows
The following tables present the estimated unaudited pro forma standardized measure of discounted future net cash flows (the “pro forma standardized measure”) at December 31, 2025. The pro forma standardized measure information set forth below gives effect to the Pro Forma Transactions as if they had been completed on January 1, 2025. Devon EF Assets Acquisition Adjustments reflect adjustments related to the tax effects resulting from the Devon EF Assets Acquisition. The disclosures below are derived from the “Standardized measure of discounted future net cash flows” for the year ended December 31, 2025 included within Crescent’s Annual Report on Form 10-


K and the supplemental oil and gas information of the Devon EF Assets. An explanation of the underlying methodology applied, as required by SEC regulations, can be found within the historical financial statements included in Crescent’s Annual Report on Form 10-K. The calculations assume the continuation of existing economic, operating and contractual conditions at December 31, 2025.
The pro forma standardized measure is not necessarily indicative of the results that might have occurred had the Pro Forma Transactions been completed on January 1, 2025 and is not intended to be a projection of future results. Future results may vary significantly from the results reflected because of various factors, including those discussed in “Risk Factors” included in Crescent’s Annual Report on Form 10-K.
The pro forma standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves as of December 31, 2025 is as follows:
(in thousands)
Crescent
(Historical)		2025 Acquisitions AdjustmentsCrescent Pro Forma for 2025 AcquisitionsDevon EF Assets (Historical)Devon EF Assets Acquisition AdjustmentsCrescent Pro Forma Combined
Future cash inflows$32,852,573 $— $32,852,573 $6,797,000 $— $39,649,573 
Future production costs(15,003,036)— (15,003,036)(2,633,000)— (17,636,036)
Future development costs (1)
(3,387,941)— (3,387,941)(977,000)— (4,364,941)
Future income taxes(1,308,188)— (1,308,188)— (32,638)(1,340,826)
Future net cash flows$13,153,408 $— $13,153,408 $3,187,000 $(32,638)$16,307,770 
Annual discount of 10% for estimated timing(5,397,858)— (5,397,858)(1,037,000)10,010 (6,424,848)
Standardized measure of discounted future net cash flows as of December 31, 2025$7,755,550 $— $7,755,550 $2,150,000 $(22,628)$9,882,922 
______________
(1)Future development costs include future abandonment and salvage costs.
Changes in standardized measure
The disclosures below are derived from the “Changes in standardized measure” for the year ended December 31, 2025 included within Crescent’s Annual Report on Form 10-K and the supplemental oil and gas information of


the Devon EF Assets. The changes in the pro forma standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the year ended December 31, 2025 are as follows:
(in thousands)
Crescent
(Historical)		2025 Acquisitions AdjustmentsCrescent Pro Forma for 2025 AcquisitionsDevon EF Assets (Historical)Devon EF Assets Acquisition AdjustmentsCrescent Pro Forma Combined
Balance at December 31, 2024
$5,703,695 $5,610,557 $11,314,252 $1,387,000 $(15,913)$12,685,339 
Net change in prices and production costs(2,011,577)(1,347,360)(3,358,937)(254,000)— (3,612,937)
Net change in future development costs872,553 97,942 970,495 (45,000)— 925,495 
Sales and transfers of oil and natural gas produced, net of production expenses(2,075,124)(945,323)(3,020,447)(732,000)— (3,752,447)
Extensions, discoveries, additions and improved recovery, net of related costs606,461 358,075 964,536 779,000 — 1,743,536 
Purchases of reserves in place4,652,989 (4,442,111)210,878 714,000 — 924,878 
Sales of reserves in place(553,700)(27,160)(580,860)(3,000)— (583,860)
Revisions of previous quantity estimates(208,348)(358,613)(566,961)56,000 — (510,961)
Previously estimated development costs incurred399,891 427,871 827,762 143,000 — 970,762 
Net change in taxes(92,507)321,658 229,151 — (5,124)224,027 
Accretion of discount615,853 462,594 1,078,447 105,000 (1,591)1,181,856 
Changes in timing and other(154,636)(158,130)(312,766)— — (312,766)
Balance at December 31, 2025
$7,755,550 $— $7,755,550 $2,150,000 $(22,628)$9,882,922 

Source: View Original Filing on SEC EDGAR

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