Vital Energy : June 2025 Investor Presentation

Published: 2025-06-23 16:36:04 ET VTLE

Published on 06/23/2025 at 16:36

‌June 2025‌

Investor Presentation

June 23, 2025

This presentation, including any oral statements made regarding the contents of this presentation, contains forward-looking statements as defined under Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, that address activities that Vital Energy, Inc. (together with its subsidiaries, the "Company", "Vital Energy" or "VTLE") assumes, plans, expects, believes, intends, projects, indicates, enables, transforms, estimates or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. The forward-looking statements are based on management's current belief, based on currently available information, as to the outcome and timing of future events. Such statements are not guarantees of future performance and involve risks, assumptions and uncertainties.

General risks relating to Vital Energy include, but are not limited to: the volatility of oil, NGL and natural gas prices, including the Company's area of operation in the Permian Basin; changes, uncertainty and instability in domestic and global production, supply and demand for oil, NGL and natural gas, and actions by the Organization of the Petroleum Exporting Countries members and other oil exporting nations ("OPEC+"); changes in general economic, business or industry conditions and market volatility, including as a result of slowing growth, inflationary pressures, monetary policy, tariffs, trade barriers, price and exchange controls and other regulatory requirements, including such changes that may be implemented by the United States ("U.S.") and foreign governments; the Company's ability to execute its strategies, including its ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to its financial results and to successfully integrate acquired businesses, assets and properties; the Company's ability to optimize spacing, drilling and completions techniques in order to maximize its rate of return, cash flows from operations and stockholder value; the ongoing instability and uncertainty in the U.S. and international energy, financial and consumer markets that could adversely affect the liquidity available to the Company and its customers and the demand for commodities, including oil, NGL and natural gas; competition in the oil and gas industry; the Company's ability to discover, estimate, develop and replace oil, NGL and natural gas reserves and inventory; insufficient transportation capacity in the Permian Basin and challenges associated with such constraint, and the availability and costs of sufficient gathering, processing, storage and export capacity; a decrease in production levels which may impair the Company's ability to meet its contractual obligations and ability to retain its leases; risks associated with the uncertainty of potential drilling locations and plans to drill in the future; the inability of significant customers to meet their obligations; revisions to the Company's reserve estimates as a result of changes in commodity prices, decline curves and other uncertainties; the availability and costs of drilling and production equipment, supplies, labor and oil and natural gas processing and other services; ongoing war and political instability in Ukraine, Israel and the Middle East and the effects of such conflicts on the global hydrocarbon market and supply chains; risks related to the geographic concentration of the Company's

assets; the Company's ability to hedge commercial risk, including commodity price volatility, and regulations that affect the Company's ability to hedge such risks; the Company's ability to continue to maintain the borrowing capacity under its Senior Secured Credit Facility or access other means of obtaining capital and liquidity, especially during periods of sustained low commodity prices; the Company's ability to comply with restrictions contained in its debt agreements, including its Senior Secured Credit Facility and the indentures governing its senior unsecured notes, as well as debt that could be incurred in the future; the Company's ability to generate sufficient cash to service its indebtedness, fund its capital requirements and generate future profits; drilling and operating risks, including but not limited to, risks related to hydraulic fracturing, securing

sufficient electricity to produce its wells without limitation, natural disasters and other matters beyond the Company's control; U.S. and international economic conditions and legal, tax, political and administrative developments, including the effects of energy, trade and environmental policies and existing and future laws and government regulations; the Company's ability to comply with federal, state and local regulatory

requirements; the impact of repurchases, if any, of securities from time to time; the Company's ability to maintain the health and safety of, as well as recruit and retain, qualified personnel, including senior management or other key personnel, necessary to operate its business; evolving cybersecurity risks such as those involving unauthorized access, denial-of-service attacks, third-party service provider failures, malicious software, data privacy breaches by employees, insiders or others with authorized access, cyber or phishing attacks, ransomware, social engineering, physical breaches or other actions; and the Company's belief that the outcome of any current legal proceedings will not materially affect its financial results and operations

Any forward-looking statement speaks only as of the date on which such statement is made. Vital Energy does not intend to, and disclaims any obligation to, correct, update or revise any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

This presentation includes financial measures that are not in accordance with generally accepted accounting principles ("GAAP"), such as Adjusted Free Cash Flow, Net Debt, PV-10 and Consolidated EBITDAX. While management believes that such measures are useful for investors, they should not be used as a replacement for financial measures that are in accordance with GAAP. For definitions of such non-GAAP financial measures and their reconciliations to the most comparable GAAP measures, please see the Appendix. This presentation also includes certain forward-looking non-GAAP measures. Due to the forward-looking nature of such measures, no reconciliations of these non-GAAP measures to their respective most directly comparable GAAP measures are available without unreasonable efforts. This is due to the inherent difficulty of forecasting the timing or amount of various reconciling items that would impact the most directly comparable forward-looking GAAP financial measure, that have not yet occurred, are out of the Company's control and/or cannot be reasonably predicted. Accordingly, such reconciliations are excluded from this presentation. Forward-looking non-GAAP financial measures provided without the most directly comparable GAAP financial measures may vary from the corresponding GAAP financial measures.

Unless otherwise specified, references to "average sales price" refer to average sales price excluding the effects of the Company's derivative transactions. All amounts, dollars and percentages presented in this

presentation are rounded and therefore approximate.

OPTIMIZE

COST STRUCTURE

IMPROVE

WTI BREAKEVEN

MAXIMIZE

ADJUSTED FCF1

REDUCE

ABSOLUTE DEBT

Permian Basin Summary

Howard Co.

Net Acres2

~273,000

FY-25E Total Production

135.3 - 139.8 MBOE/d

FY-25E % Oil

47%

Inventory Locations3

~925

TX Glasscock Co.

Ector Co.

Midland Co.

Winkler Co.

Ward Co.

Crane Co. Upton Co.

Reagan Co.

Reeves Co.

Pecos Co.

VTLE Acreage

1See Appendix for definitions and reconciliations of non-GAAP financial measures. 2As of March 31, 2025. 3Gross operated locations as of January 2025 and excludes upside inventory.

Renegotiation of service contracts inherited from acquisitions to better terms and lower costs

Savings from conversion to high-line power and lease gas to power generators

Consolidation of lease operator routes

Lease Operating Expenses, $MM

$112.0 - $118.0 MM

$107.0 - $113.0 MM

Optimization of chemical treatment parameters

2Q-25

Guidance

YE-25 Projected

Exit Rate

Reduced employee/contractor headcount by ~10%

Rationalized corporate expenses to align with pivot from acquisition strategy to asset optimization

General and Administrative Expenses1, $MM

$21.0 - $23.5 MM

$24.6 - $26.7 MM

2Q-25

Guidance

YE-25 Projected

Exit Rate

1General and administrative expenses includes LTIP cash/non-cash and excludes transaction expenses.

1H-25 Program

~$57 WTI Breakeven1

D-Day

Delaware Basin

2 Wells

1Q-25

Grissom White

Delaware Basin

2 Wells

1Q-25

Mosaic State

Delaware Basin

6 Wells

1Q-25

Duiker Lynx

Delaware Basin

6 Wells

1Q-25

Emily Boss

Delaware Basin

3 Wells

1Q-25

Scrat

Delaware Basin

2 Wells

1Q-25

Pinto

Delaware Basin

2 Wells

1Q-25

Dire Wolf

Delaware Basin

3 Wells

2Q-25

Durlene

Delaware Basin

4 Wells

2Q-25

Aloha State

Delaware Basin

2 Wells

2Q-25

The Colonel

Midland Basin

2 Wells

2Q-25

Tiger

Midland Basin

1 Well

2Q-25

Agate

Delaware Basin

1 Well

2Q-25

Getlo

Midland Basin

2 Wells

2Q-25

H-

Lil EL

25 Program

Midland Basin

2 Wells

2Q-25

$46

WTI Breakev

Fat Chance

en1

Delaware Basin

2 Wells

3Q-25

Army South

Delaware Basin

6 Wells

3Q-25

Cox

Midland Basin

8 Wells

3Q-25

Navy South

Delaware Basin

8 Wells

3Q-25

Rambo State

Delaware Basin

3 Wells

3Q-25

8 Mile

Midland Basin

12 Wells

4Q-25

Rig Count

Delaware Basin

Midland Basin

Combined

Howard Co.

Glasscock Co.

Midland Co.

Upton Co. Reagan Co.

3.4

1.8

5.2

Frac Crews

0.9

0.4

1.3

Spuds

40 Gross (31.9 Net)

42 Gross (33.9 Net)

82 Gross (65.8 Net)

Completions

52 Gross (40.2 Net)

27 Gross (21.6 Net)

79 Gross (61.8 Net)

Turn-in-Lines

52 Gross (40.2 Net)

27 Gross (21.3 Net)

79 Gross (61.5 Net)

NM TX

Ector Co.

Winkler Co.

Crane Co.

Ward Co.

Reeves Co.

Pecos Co.

Midland Basin Activity Delaware Basin Activity

1Breakeven based on minimum 10% rate of return.

Reaffirming 2025 Outlook

Oil Production, MBO/d

64.9

61.0 - 65.0

58.0 - 62.0

68.0 - 72.0

63.0 - 66.0

Oil Production (MBO/d)

135.3 - 139.8

Total Production (MBOE/d)

$835 - $915 MM

Capital Investments

~$265 MM

Adjusted Free Cash Flow1,2

1Q-25A 2Q-25E 3Q-25E 4Q-25E

Capital Investments, $MM Total Production, MBOE/d

$260 - $290

128.0 - 134.0

$253

$215 - $245

$105 - $125

140.2 133.0 - 139.0

140.0 - 146.0

1Q-25A 2Q-25E 3Q-25E 4Q-25E 1Q-25A 2Q-25E 3Q-25E 4Q-25E

1See Appendix for definitions and reconciliations of non-GAAP financial measures. 2Assumes May 6, 2025, commodity prices. Bal-25 of $58.70 WTI and $3.92 Henry Hub.

Debt Maturity Profile, $MM3,4

$735

$665

Drawn Credit Facility

Undrawn Credit Facility

$29

$302

$298

$1,000

Cash Balance Sr. Notes

Credit Facility

Current

Borrowing Base

$1.40 B

Elected Commitment

$1.40 B

Total Liquidity

$695 MM

Cash Balance 3/31/2025

2025 2026 2027 2028 2029

(7.750%)

2030

(9.750%)

2031 2032

(7.875%)

2025E Adjusted Free Cash Flow1,2Sensitivity, $MM 2025E Net Debt Reduction, $MM1

$2,440

$21

$112

$2,307

~$170

~$2,140

~$300

~$265

~$240

$50 WTI

Oil

Current Strip WTI Oil

$70 WTI

Oil

YE-24A Non-Core Divestiture

1Q-25

Paydown

1Q-25A 2Q-4Q

Targeted

YE-25E

1Assumes May 6, 2025, commodity prices. Bal-25 of $58.70 WTI and $3.92 Henry Hub. 2See Appendix for definitions and reconciliations of non-GAAP financial measures. 3As of March 31, 2025.

Crude Oil Hedge Position, MBO1Natural Gas Hedge Position, MMBTU1Natural Gas Liquids Hedge Position, MBBL1

Hedges as May 9, 2025

10,388

11,279

4,005

3,285

2H-25 FY-26 FY-27

32,238,000

43,800,000

51,830,000

2H-25 FY-26 FY-27

0 0

3,956

2H-25 FY-26 FY-27

3Q-25

4Q-25

2H-25

1Q-26

2Q-26

3Q-26

4Q-26

FY-26

FY-27

Crude Oil (MBO) (Price $/BBO)

WTI Swaps

5,226

6,054

11,279

3,825

3,686

2,898

13,307

3,285

Price

$70.06

$67.75

$68.82

$65.09

$63.70

$63.52

$64.02

$61.07

WTI Collars

540

546

1,086

Put Price

$60.00

Call Price

$71.02

Natural Gas (MMBTU) (Price $/MMBTU)

Waha Inside FERC Swaps

17,204,000

15,034,000

32,238,000

12,780,000

12,922,000

13,064,000

51,830,000

43,800,000

Price

$2.32

$2.41

$2.70

Natural Gas Liquids (MBBL)

(Price $/BBL)

Propane Swaps

874

1,748

Price

$34.16

Ethane Swaps

1,104

2,208

Price

$11.04

1Hedges executed as of June 17, 2025.

~250 Upside

~3 Years of Incremental Inventory Economically Viable; Future Evaluation Required

~925 Locations

>11 Years of Inventory1

~$53 Avg. WTI Breakeven Oil Price

Midland Basin Completable Lateral Feet ~8,292,000'

~250

~1,175

Jan-25 Inventory

Illustrative 5% DC&E Savings

~830

~925

+95

~445

+385

Jan-23

2023

Jan-24

2024

Jan-25

Upside

Base + Upside

Inventory

Additions

Inventory

Additions

Inventory

Locations

~5%

~35%

~60%

~15%

~50%

~35%

~300% Increase in Sub-$50 WTI Breakeven Total Completable Lateral Feet vs. 2023

Delaware Basin Completable Lateral Feet ~3,548,000'

Jan-25 Inventory Illustrative 5% DC&E Savings

~35%

4,962,000'

~35%

~40%

~25%

~40%

~45%

Jan-25 Inventory

~15%

~45%

~40%

~20%

~35%

~45%

~15%

11,840,000'

Jan-24 Inventory

9,172,000'

Jan-23 Inventory

1Gross operated locations as of January 2025 at current activity pace and spacing and excludes upside inventory.

2025 Delaware Basin J-Hook Well Development

2025 Midland Basin Horseshoe Well Development Improves Capital Efficiency ~30%

MSS

1 Wells

Jo Mill 3 Wells

LSS

2 Wells

Dean

WCA

3 Wells

WCB

3 Wells

WCC

WCD

Midland Co.

VTLE Acreage

J-Hook Design - WCB

Midland Basin

Howard Co.

Glasscock Co.

Midland Co.

Upton Co. Reagan Co.

Delaware Basin

Winkler Co.

Ward Co.

Reeves Co.

Pecos Co.

VTLE Acreage

J-Hook Design - WCB

Capital Savings1

($MM)

~$125

Capital Efficiency

($/1-yr BOE)

~$90

$55

Avg. WTI Breakeven

(Oil $/Bbl)

$40

$62

$40

Straight LL Development (24 - 5K Wells)

Horseshoe Development (12 - 10K

Wells)

Straight LL Development (24 - 5K Wells)

Horseshoe Development (12 - 10K

Wells)

Straight LL Development (24 - 5K Wells)

Horseshoe Development (12 - 10K

Wells)

1Gross figures represented.

Midland Basin

Howard Co.

Glasscock Co.

Ector Co.

Midland Co.

Upton Co.

Reagan Co.

Crane Co.

Key Stats

Net Acres1

~191,500

Inventory Locations2

~620 Gross

Lateral Length

~13,400'

Completable Lateral Feet

8,292,000'

Avg. WTI Breakeven Oil Price

~$52

Inventory Ownership

86% WI | 65% NRI

% of FY-25E Capital Program

~35%

Program Productivity Increase in 2025 versus 2024

250

$63 $67

$53

$47

FY-24 FY-25E FY-24 FY-25E

Midland Basin Delaware Basin Program Program

Cumulative Gross MBOE

(Production per Well)

200

150

100

12,100' LL

~2% Increase in Volume; ~3% Decrease in Lateral Length

(70% Oil)

12,500' LL

(65% Oil)

2025 Development Program

2025 Program

2024 Program

- 60 120 180 240 300 360

Producing Days

Completed Lateral Length

12 12

(ft.)

12,500' 12,100'

DC&E Capital Cost

($/Ft.)

$820

Capital Efficiency

($/1-yr BOE)

$715

$63

$53

1Q-25 2Q-25E 3Q-25E 4Q-25E

FY-24 FY-25E

Note: All figures are approximate.

FY-24 FY-25E

1As of March 31, 2025. 2Gross operated locations as of January 2025 at current activity pace and spacing and excludes upside inventory. Note: Barnett leasehold and inventory included in Midland Basin totals.

Delaware Basin

Winkler Co.

Ward Co.

Reeves Co.

Pecos Co.

Key Stats

Net Acres1

~81,500

Inventory Locations2

~305 Gross

Lateral Length

~11,600'

Completable Lateral Feet

3,548,000'

Avg. WTI Breakeven Oil Price

~$55

Inventory Ownership

72% WI | 55% NRI

% of FY-25E Capital Program

~65%

Program Productivity Increase in 2025 versus 2024

2025 Development Program

350

Cumulative Gross MBOE

(Production per Well)

300

250

200

150

100

~48% Increase in Volume; ~25% Increase in Lateral Length

13,500' LL

(68% Oil)

10,750' LL

(68% Oil)

2025 Program

2024 Program

- 60 120 180 240 300 360

Producing Days

1Q-25 2Q-25E 3Q-25E 4Q-25E

Completed Lateral Length

(ft.)

10,750'

19 19

13,500'

FY-24 FY-25E

Note: All figures are approximate.

DC&E Capital Cost

($/Ft.)

$890

$1,000

FY-24 FY-25E

Capital Efficiency

($/1-yr BOE)

$67

$47

FY-24 FY-25E

1As of March 31, 2025. 2Gross operated locations as of January 2025 at current activity pace and spacing and excludes upside inventory. Note: All figures are approximate.

Enhancing capital efficiency through increased productivity and lateral lengths

Targeting Net Debt1reduction of ~$300 MM2by YE-25 at current commodity prices

~90% of expected Bal-25 oil production hedged at ~$71 per barrel WTI

2025 development plan has estimated ~$50 per barrel3WTI breakeven

1See Appendix for definitions and reconciliations of non-GAAP financial measures. 2Assumes May 6, 2025, commodity prices. Bal-25 of $58.70 WTI and $3.92 Henry Hub.

3Breakeven based on minimum 10% rate of return.

‌Appendix

Apr-25

May-25

Jun-25

2Q-25 Avg.

Crude Oil:

WTI NYMEX ($/BBO)

$62.96

$58.83

$58.57

$60.10

WTI Midland ($/BBO)

$64.06

$59.78

$59.32

$61.03

WTI Houston ($/BBO)

$64.33

$60.12

$59.55

$61.31

Natural Gas:

Henry Hub ($/MMBTU)

$3.95

$3.17

$3.46

$3.52

Waha ($/MMBTU)

($0.94)

$0.62

$1.73

$0.47

Natural Gas Liquids:

C2 ($/BBL)

$10.68

$10.15

$10.45

$10.42

C3 ($/BBL)

$35.82

$29.72

$29.61

$31.70

IC4 ($/BBL)

$37.38

$38.47

$38.12

$37.99

NC4 ($/BBL)

$36.97

$38.40

$36.65

$37.35

C5+ ($/BBL)

$56.18

$54.10

$54.39

$54.88

Composite ($/BBL)1

$27.68

$25.40

$25.32

$26.12

Guidance Commodity Prices Used for 2Q-25

2Q-25 FY-25

Production:

Total Production (MBOE/D)

133.0 - 139.0

135.3 - 139.8

Crude Oil Production (MBO/D)

61.0 - 65.0

63.0 - 66.0

Capital Expenditures ($MM):

$215 - $245

$835 - $915

Average Sales Price Realizations (excluding derivatives):

Crude Oil (% of WTI)

101%

Natural Gas Liquids (% of WTI)

24%

Natural Gas (% of Henry Hub)

14%

Net Settlements Received (Paid) for Matured Commodity Derivatives ($MM):

Crude Oil ($MM)

$69

Natural Gas Liquids ($MM)

Natural Gas ($MM)

$21

Operating Costs and Expenses ($MM):

Lease Operating Expenses

$112 - $118

Production and Ad Valorem Taxes (% of Oil, NGL & Natural Gas Revenues)

6.60%

Oil Transportation and Marketing Expenses

$10.7 - $11.7

Gas Gathering, Processing and Transportation Expenses

$6.7 - $7.7

General and Administrative Expenses (excluding LTIP & Transaction Expense)

$21.0 - $22.5

General and Administrative Expenses (LTIP Cash)

$0.6 - $0.7

General and Administrative Expenses (LTIP Non-Cash)

$3.0 - $3.5

Depletion, Depreciation and Amortization

$180 - $190

1Current NGL composition C2 (42%), C3 (33%), IC4 (3%), NC4 (11%) and C5+ (11%).

PUD

Total Proved Reserves, MMBOE PV-10 Reserve Value Sensitivity, $MM1

PUD

~22% of Inventory Currently Booked as PUDs

30 455

71%

70%

29%

30%

$5,179

$4,510

$4,133

$3,131

SEC

$60

$70

$80

$2,813

$318

$3,489

$3,718

$4,174

$644

$792

$1,005

(49)

12% Total Proved Reserves Increase

YE-23 2024

Production

Purchase of Reserves

Price & Other Revisions plus Additions

YE-24

Oil Price $75.48/bbl

(Gas Price $2.13/mcf)

Benchmark WTI Oil Price $/bbl

(Benchmark HH Gas Price assumes $3.00/mcf)

Proved Reserves Components, YE-24 YE-24 PDP Base Production Decline Expectations2

Proved Developed Proved Undeveloped

42%

Oil Production, MBO/D

27%

20%

16%

14%

36%

Total Production, MBOE/D

21%

17%

14%

12%

Natural

Gas 31%

Oil

37%

NGL

32%

Natural

Gas 25%

Oil

47%

NGL

28%

FY-25 FY-26 FY-27 FY-28 FY-29 FY-25 FY-26 FY-27 FY-28 FY-29

1See Appendix for definitions and reconciliations of non-GAAP financial measures. 2Based only on wells categorized as Proved Developed as of YE-24 and decline calculated Dec to Dec. Note: SEC pricing $75.48 benchmark oil and $2.13 benchmark gas.

Continued Progress Toward Sustainability Targets

CATEGORY

TARGET

2023 PERFORMANCE3

TARGET PROGRESS

2025

Scope 1

GHG emissions intensity1

Below 12.5 mtCO2e/MBOE

2019 baseline of 26.03 mtCO2e/MBOE

9.14 mtCO2e / MBOE

Achieved

65% reduction from baseline

Methane Emissions2

Below 0.20%

2019 baseline of 0.87%

0.08%

Achieved

90% reduction from baseline

Recycled water

50% used for completion operations 2019 baseline of 35% water recycling rate (8 million bbls recycled)

57% water recycling rate

Achieved

More then 20.5 million bbls recycled

Routine flaring

Zero

2019 baseline of 867 MMCF/year

366 MMCF/year

58% reduction to date

2030

Combined Scope 1 and 2

GHG emissions intensity

Below 10 mtCO2e/MBOE

2019 baseline of 26.53 mtCO2e/MBOE

11.94 mtCO2e/MBOE

55% reduction to date

1Scope 1 GHG metrics are based on EPA Subpart W reporting; all performance is as of December 31, 2023. 2As a percentage of natural gas produced.

32023 performance is inclusive of acquisitions closed in the 2023 calendar year.

Adjusted Free Cash Flow

Free Cash Flow is a non-GAAP financial measure that the Company defines as net cash provided by (used in) operating activities (GAAP) before net changes in operating assets and liabilities and transaction expenses related to non-budgeted acquisitions, less capital investments, excluding non-budgeted acquisition costs. Management believes Adjusted Free Cash Flow is useful to management and investors in evaluating operating trends in its business that are affected by production, commodity prices, operating costs and other related factors. There are significant limitations to the use of Adjusted Free Cash Flow as a measure of performance, including the lack of comparability due to the different methods of calculating Adjusted Free Cash Flow reported by different companies.

This release also includes certain forward-looking non-GAAP measures. Due to the forward-looking nature of such measures, no reconciliations of these non-GAAP measures to their respective most directly comparable GAAP measure are available without unreasonable efforts. This is due to the inherent difficulty of forecasting the timing or amount of various reconciling items that would impact the most directly comparable forward-looking GAAP financial measure, that have not yet occurred, are out of the Company's control and/or cannot be reasonably predicted. Accordingly, such reconciliations are excluded from this release. Forward-looking non-GAAP financial measures provided without the most directly comparable GAAP financial measures may vary materially from the corresponding GAAP financial measures.

The following table presents a reconciliation of net cash provided by (used in) operating activities (GAAP) to Adjusted Free Cash Flow (non-GAAP) for the periods presented:

Three months ended

(in thousands, unaudited)

March 31,

2025

Net cash provided by (used in) operating activities

$350,985

Less:

Net changes in operating assets and liabilities

33,821

Cash flows from operating activities before net changes in operating assets and liabilities and transaction expenses related to non-budgeted acquisitions

317,164

Less capital investments, excluding non-budgeted acquisition costs:

Oil and natural gas properties1

251,264

Midstream and other fixed assets1

1,407

Total capital investments, excluding non-budgeted acquisition costs

252,671

Adjusted Free Cash Flow (non-GAAP)

$64,493

1Includes capitalized share-settled equity-based compensation and asset retirement costs.

Consolidated EBITDAX

Consolidated EBITDAX is a non-GAAP financial measure defined in the Company's Senior Secured Credit Facility as net income or loss (GAAP) plus adjustments for share-settled equity-based compensation, depletion, depreciation and amortization, impairment expense, organizational restructuring expenses, gains or losses on disposal of assets, mark-to-market on derivatives, accretion expense, interest expense, income taxes and other non-recurring income and expenses. Consolidated EBITDAX provides no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, working capital movement or tax position. Consolidated EBITDAX does not represent funds available for future discretionary use because it excludes funds required for debt service, capital expenditures, working capital, income taxes, franchise taxes and other commitments and obligations. However, management believes Consolidated EBITDAX is useful to an investor because this measure:

is used by investors in the oil and natural gas industry to measure a company's operating performance without regard to items that can vary substantially from company to company depending upon accounting methods, the book value of assets, capital structure and the method by which assets were acquired, among other factors;

helps investors to more meaningfully evaluate and compare the results of the Company's operations from period to period by removing the effect of the Company's capital structure from the Company's operating structure; and

is used by management for various purposes, including (i) as a measure of operating performance, (ii) as a measure of compliance under the Senior Secured Credit Facility, (iii) in presentations to the board of directors and (iv) as a basis for strategic planning and forecasting.

There are significant limitations to the use of Consolidated EBITDAX as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the Company's net income or loss and the lack of comparability of results of operations to different companies due to the different methods of calculating Consolidated EBITDAX, or similarly titled measures, reported by different companies. The Company is subject to financial covenants under the Senior Secured Credit Facility, one of which establishes a maximum permitted ratio of Net Debt, as defined in the Senior Secured Credit Facility, to Consolidated EBITDAX. See Note 7 in the 2024 Annual Report, to be filed with the SEC, for additional discussion of the financial covenants under the Senior Secured Credit Facility. Additional information on Consolidated EBITDAX can be found in the Company's Eleventh Amendment to the Senior Secured Credit Facility, as filed with the SEC on September 13, 2023.

Consolidated EBITDAX

The following table presents a reconciliation of net income (loss) (GAAP) to Consolidated EBITDAX (non-GAAP) for the periods presented:

Three months ended

(in thousands, unaudited)

March 31,

2025

Net income (loss)

($18,837)

Plus:

Share-settled equity-based compensation

3,604

Depletion, depreciation and amortization

189,900

Impairment expense

158,241

(Gain) loss on disposal of assets, net

(110)

Mark-to-market on derivatives:

(Gain) loss on derivatives, net

(44,171)

Settlements received (paid) for matured derivatives, net

20,687

Accretion expense

1,034

Interest expense

50,380

Income tax (benefit) expense

(1,049)

Consolidated EBITDAX (non-GAAP)

$359,679

Consolidated EBITDAX

The following table presents a reconciliation of net cash provided by (used in) operating activities (GAAP) to Consolidated EBITDAX (non-GAAP) for the periods presented:

Three months ended

(in thousands, unaudited)

March 31,

2025

Net cash provided by (used in) operating activities

$350,985

Plus:

Interest expense

50,380

Current income tax (benefit) expense

762

Net changes in operating assets and liabilities

(33,821)

Other, net

(8,627)

Consolidated EBITDAX (non-GAAP)

$359,679

Net Debt

Net Debt is a non-GAAP financial measure defined in the Company's Senior Secured Credit Facility as the face value of long-term debt plus any outstanding letters of credit, less cash and cash equivalents, where cash and cash equivalents are capped at $100 million when there are borrowings on the Senior Secured Credit Facility. Management believes Net Debt is useful to management and investors in determining the Company's leverage position since the Company has the ability, and may decide, to use a portion of its cash and cash equivalents to reduce debt.

(in thousands, unaudited)

March 31, 2025

December 31, 2024

Total senior unsecured notes

$1,600,578

Senior Secured Credit Facility

735,000

880,000

Total long-term debt

2,335,578

2,480,578

Less: cash and cash equivalents

28,649

40,179

Net Debt (non-GAAP)

$2,306,929

$2,440,399

PV-10

PV-10 is a non-GAAP financial measure that is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the standardized measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10 percent. Management believes that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to the Company's estimated proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of the Company's proved oil, NGL and natural gas assets. Further, investors may utilize the measure as a basis for comparison of the relative size and value of proved reserves to other companies. The Company uses this measure when assessing the potential return on investment related to proved oil, NGL and natural gas assets. However, PV-10 is not a substitute for the standardized measure of discounted future net cash flows. The PV-10 measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of the Company's oil, NGL and natural gas reserves of the property.

(in millions, unaudited)

December 31, 2024

Standardized measure of discounted future net cash flows

$4,215

Less: present value of future income taxes discounted at 10%

(295)

PV-10 (non-GAAP)

$4,510

Disclaimer

Vital Energy Inc. published this content on June 23, 2025, and is solely responsible for the information contained herein. Distributed via Public Technologies (PUBT), unedited and unaltered, on June 23, 2025 at 20:35 UTC.