1Q-23 Earnings Presentation EXHIBIT 99.2
Forward-Looking / Cautionary Statements 2 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” 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, continuing and worsening inflationary pressures and associated changes in monetary policy that may cause costs to rise; changes in domestic and global production, supply and demand for commodities, including as a result of the coronavirus ("COVID-19") pandemic, actions by the Organization of Petroleum Exporting Countries and other producing countries ("OPEC+") and the Russian-Ukrainian military conflict, the decline in prices of oil, natural gas liquids and natural gas and the related impact to financial statements as a result of asset impairments and revisions to reserve estimates, reduced demand due to shifting market perception towards the oil and gas industry; competition in the oil and gas industry; the ability of the Company 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, pipeline transportation and storage constraints in the Permian Basin, the effects and duration of the outbreak of disease, such as the COVID-19 pandemic, and any related government policies and actions, long-term performance of wells, drilling and operating risks, the possibility of production curtailment, the impact of new laws and regulations, including those regarding the use of hydraulic fracturing, the impact of legislation or regulatory initiatives intended to address induced seismicity on our ability to conduct our operations; hedging activities, tariffs on steel, the impacts of severe weather, including the freezing of wells and pipelines in the Permian Basin due to cold weather, possible impacts of litigation and regulations, the impact of the Company's transactions, if any, with its securities from time to time, the impact of new environmental, health and safety requirements applicable to the Company's business activities, the possibility of the elimination of federal income tax deductions for oil and gas exploration and development and other factors, including those and other risks described in its Annual Report on Form 10-K for the year ended December 31, 2022 and those set forth from time to time in other filings with the Securities and Exchange Commission ("SEC"). Any forward-looking statement speaks only as of the date on which such statement is made. Vital 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. The SEC generally permits oil and natural gas companies, in filings made with the SEC, to disclose proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, and certain probable and possible reserves that meet the SEC’s definitions for such terms. In this presentation, the Company may use the terms “resource potential,” “resource play,” “estimated ultimate recovery,” or “EURs,” “type curve” and “standardized measure,” each of which the SEC guidelines restrict from being included in filings with the SEC without strict compliance with SEC definitions. These terms refer to the Company’s internal estimates of unbooked hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques. “Resource potential” is used by the Company to refer to the estimated quantities of hydrocarbons that may be added to proved reserves, largely from a specified resource play potentially supporting numerous drilling locations. A “resource play” is a term used by the Company to describe an accumulation of hydrocarbons known to exist over a large areal expanse and/or thick vertical section potentially supporting numerous drilling locations, which, when compared to a conventional play, typically has a lower geological and/or commercial development risk. “EURs” are based on the Company’s previous operating experience in a given area and publicly available information relating to the operations of producers who are conducting operations in these areas. Unbooked resource potential and “EURs” do not constitute reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or SEC rules and do not include any proved reserves. Actual quantities of reserves that may be ultimately recovered from the Company’s interests may differ substantially from those presented herein. Factors affecting ultimate recovery include the scope of the Company’s ongoing drilling program, which will be directly affected by the availability of capital, decreases in oil, natural gas liquids and natural gas prices, well spacing, drilling and production costs, availability and cost of drilling services and equipment, lease expirations, transportation constraints, regulatory approvals, negative revisions to reserve estimates and other factors, as well as actual drilling results, including geological and mechanical factors affecting recovery rates. “EURs” from reserves may change significantly as development of the Company’s core assets provides additional data. In addition, the Company’s production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases. “Type curve” refers to a production profile of a well, or a particular category of wells, for a specific play and/or area. The “standardized measure” of discounted future new cash flows is calculated in accordance with SEC regulations and a discount rate of 10%. Actual results may vary considerably and should not be considered to represent the fair market value of the Company’s proved reserves. This presentation includes financial measures that are not in accordance with generally accepted accounting principles (“GAAP”), such as Free Cash Flow 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, please see the Appendix. 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.
3 Exceeded high-end of production guidance for both oil and total production • Production from both base and new wells exceeding expectations • Increased full-year 2023 oil and total production guidance in April 2023 • Proprietary digital solutions providing production uplift through ESP and gas lift runtime improvements Reported incurred capital expenditures below guidance • Inflationary pressures moderating for key products and services • Added four TILs to full-year 2023 through completion efficiencies • Expect full-year 2023 capital expenditures to be at midpoint of guidance range Announced accretive Midland Basin acquisition (Closed April 2023) • 11,200 net acres in Upton and South Reagan counties • Added 30 gross locations Achieved 2025 emissions targets • Disclosed preliminary greenhouse gas and methane intensity levels for 2022 • 2022 Scope 1 GHG intensity of 10.7 metric tons of CO2 equivalent/MBOE versus 2025 target of 12.5 • 2022 methane intensity of 0.10% of natural gas produced versus 2025 target of 0.20% Strong First-Quarter 2023 Performance Oil Production | MBO/d 38.51Q-23 Guidance Range 33.0 – 36.0 Total Production | MBOE/d 80.41Q-23 Guidance Range 72.5 – 76.5 Incurred Capital Expenditures | $MM $1881Q-23 Guidance Range $210 – $230
0 25 50 75 100 125 150 175 200 0 60 120 180 240 300 360 C u m u la ti ve G ro ss O il P ro d u ct io n p e r W e ll (M B O ) Producing Days Disciplined Strategy Underpins Long-Term Value Creation 1See Appendix for definitions of non-GAAP financial measures; 2Gross operated locations as of January 2023; 31Q-23 Actuals ; 4FY-23 estimate; not included in 1Q-23 production 5Production data normalized for 10,000’ lateral length and downtime 4 Maintain Capital Discipline Generate Free Cash Flow1 Reduce Debt and Leverage Target Accretive Transactions Advance Sustainability Integrate Digital Solutions Pure-Play Midland Basin Producer Howard Glasscock Reagan Upton Howard ~31,650 net acres ~40.9 MBoe/d3 ~73% oil W. Glasscock ~38,350 net acres ~10.5 MBoe/d3 ~43% oil E. Glasscock ~32,400 net acres ~4.0 MBoe/d3 ~20% oil Reagan ~60,550 net acres ~24.9 MBoe/d3 ~13% oilUpton / S. Reagan ~11,200 net acres ~2.6 MBoe/d4 ~50% oil VTLE Net Acres Inventory Locations2 ~115Howard ~295W. Glasscock ~35E. Glasscock ~30Upton / S. Reagan ~475Total ~185Upside Strong Well Performance5 Across the Portfolio N. Howard C. Howard W. Glasscock Upton / S. Reagan
Initial Howard County (4Q-19) ~7,400 net acres Initial W. Glasscock (4Q-19) ~4,475 net acres Howard Bolt-On (1Q-20) ~1,100 net acres Howard Bolt-On (4Q-20) ~2,750 net acres Howard County (2Q-21) ~21,000 net acres E. Glasscock / Reagan (2Q-21) WI Divestiture W. Glasscock County (3Q-21) ~20,000 net acres Howard Non-Op Divestiture (3Q-22) ~1,650 net acres Upton / S. Reagan (Driftwood) (1Q-23) ~11,200 net acres Accretive Transactions Driving Company Performance 1See Appendix for definitions of non-GAAP financial measures; 2FY-23E assumes $76 oil / $3.42 gas price for 1Q and $75 oil / $2.50 gas price for remaining year and mid-point of capital guidance; 3Calculation conforms to credit facility covenant which requires various treatment of asset transaction impacts 5 Martin Howard Midland Glasscock Upton Reagan Oil Production Growth | MBO/d E. Glasscock/Reagan Net Acres Acquired Net Acres Oil-Weighted Transactions | 4Q-19 - Current Net Debt to Consolidated EBITDAX1,3 | 0.0x 77% 32% 17% 11% 23% 68% 83% 89% 26.8 31.8 37.9 38.5 FY-20A FY-21A FY-22A 1Q-23A Acquisitions E. Glasscock / Reagan 2.61x 2.14x 1.22x 1.30x FY-20A FY-21A FY-22A 1Q-23A 2019 2020 2021 2022 2023
8.79 9.77 9.84 FY-21A FY-22A 1Q-23A Completed Stages Per Day (Primary Crew) 1,430' 1,530' 1,535' FY-21A FY-22A 1Q-23A Drilling Ft. Per Day Per Rig 9,900' 11,900' 11,600' FY-21A FY-22A 1Q-23A Avg. Completed Lateral Length Continuous Improvement Drives Capital Efficient Program DC&E 81% Facilities & Land 12% Corporate 7% Capital Efficient 2023 Development Program 6 Full Year Capital Program FY-23E Guidance $625 - $675Capital Expenditures | $MM ~2.0Avg. Rig Count | Op ~1.3Avg. Frac Crew | Op ~47 Gross (~42.8 Net)Spuds | Op ~60 Gross (~57.2 Net)Completions | Op ~59 Gross (~56.5 Net)Turn-in-Lines | Op 76.0 – 80.0Total Production | MBOE/d 36.3 – 39.3Oil Production | MBO/d Capital Allocation | FY-23E Operated Development Activity 2 2 2 2 1Q-23A 2Q-23E 3Q-23E 4Q-23E Rig Count | # 2 1 1 1 1Q-23A 2Q-23E 3Q-23E 4Q-23E Frac Crews | # 18 23 8 10 1Q-23A 2Q-23E 3Q-23E 4Q-23E Operated Turn-in-Lines | #
77 Leadership in a Low-Carbon Future OUR ENVIRONMENTAL TARGETS <0.20% METHANE EMISSIONS BY 2025 (AS A PERCENT OF NATURAL GAS PRODUCTION) ZERO ROUTINE FLARING BY 2025 <12.5 MTCO2e/MBOE SCOPE 1 GHG EMISSIONS INTENSITY BY 2025 50% RECYCLED WATER FOR COMPLETION OPERATIONS BY 2025 SCOPE 1 AND 2 GHG EMISSIONS INTENSITY < 10 MTCO2e/MBOE BY 2030 ESG PROGRESS 89% REDUCTION IN METHANE INTENSITY SINCE 2019 59% REDUCTION in SCOPE 1 GHG EMISSIONS INTENSITY SINCE 20191 42% REDUCTION IN ROUTINE FLARING SINCE 2019 FOCUSED SHORT-TERM INCENTIVE PROGRAM SO THAT ENVIRONMENTAL GOALS MAKE UP 20% AND IMPLMENTED A LONG-TERM INCENTIVE PROGRAM METRIC TIED TO ACHIEVING 2025 EMISSIONS REDUCTION GOALS FIRST PERMIAN OPERATOR TO ACHIEVE THE TRUSTWELLTM CERTIFICATION FOR RESPONSIBLE OPERATIONS CONDUCTED FIRST SUPPLIER ESG SURVEY TO BETTER UNDERSTAND THE DIVERSITY OF OUR SUPPLY BASE AND THE ESG POLICIES THEY HAVE IN PLACE INCREASED ACTIVE MANAGEMENT AND HIGH GRADING OF OUR VENDORS BASED ON SAFETY METRICS 43% OF 2021 NEW HIRES WERE DIVERSE CONDUCTED COMPANY-WIDE UNCONSCIOUS BIAS TRAINING INCREASED BOARD GENDER AND ETHNIC DIVERSITY TO 60%, A 270% INCREASE SINCE 2019 CH4 1In 2021, we closed on two acquisitions. The 2019 and 2020 emissions data published in this report has been calculated to include emissions for these acquisitions. Achieved target during 2022
Progress Toward Emissions Targets Demonstrates Continued ESG Leadership 1As a percentage of natural gas produced 8 59% Reduction 2022 Scope 1 GHG Intensity vs. 2019 Baseline 89% Reduction 2022 Methane Intensity1 vs. 2019 Baseline 42% Reduction 2022 Routine Flaring vs. 2019 Baseline Zero Incidents 2022 Employee Total Recordable Incident Rate 2022 ESG Highlights • Achieved two of our three 2025 emission reduction targets in 2022 • 58% reduction in absolute emissions driven by pneumatics and monitoring • 53% reduction in combined Scope 1 & Scope 2 GHG emissions intensity • 1st Permian Basin operator with certified responsibly sourced production • Lowest employee and contractor combined TRIR in Company history 2025 Greenhouse Gas Intensity 26.03 23.13 17.29 10.66 12.5 2025 Target G H G In te n si ty (m tC O 2 e/ M B O E) 2025 Methane Intensity1 0.87% 0.60% 0.32% 0.10% 0.20% 2025 Target M et h an e In te n si ty (M et h an e a s % o f N at u ra l G as P ro d u ce d ) 2025 Elimination of Routine Flaring 867 758 945 500 0.00% 2025 Target R o u ti n e Fl ar in g (M M C F p er Y ea r) 42% Reduction to Date 2030 Greenhouse Gas Intensity 10.0 2030 Target 27 24 19 12 G H G In te n si ty (m tC O 2 e/ M B O E) Scope 1 Scope 2 53% Reduction to Date Target Achieved Target Achieved
0.9x 1.4x VTLE Peer Avg. Compelling Investment Opportunity 1Peer group (PDCE, SM, GRNT, CPE, SWN, CHRD, MUR, CIVI, ERF, BRY, NOG, ROCC, AR, APA, OVV, CNX, MRO, MTDR, CRK, CTRA, EQT, CHK, RRC, DVN, EOG, FANG, COP, TXO, OXY, PXD, DEN, HES); 2Source Capital One Research report as of May 3, 2023; 3See Appendix for definitions of non-GAAP financial measures; 4As of May 5, 2023; 5SEC pricing $90.15 benchmark oil and $5.20 benchmark gas; 6Assumes $76 oil / $3.42 gas price for 1Q and various oil benchmarks / $2.50 gas price for remaining year; 9 Enterprise Value to PDP Value Multiple1,2 YE-22 PV-103 Reserve Value Sensitivity | $MM Enterprise Value to 2024 EBITDA Multiple1,2 FY-23E Consolidated EBITDAX3,6 Sensitivity | $MM $2,221 $2,661 $3,094 $4,142 $410 $665 $928 $1,322 $2,631 $3,325 $4,022 $5,464 $65 $75 $85 SEC Benchmark WTI Oil Price $/Bbo (Benchmark HH Gas Price assumes $3.50/mcf) $750 $825 $900 $960 $65 $75 $85 $95 Benchmark WTI Oil Price $/Bbo (Benchmark HH Gas Price assumes $2.50/mcf) 2.0x 3.7x VTLE Peer Avg. Significant Upside Potential Significant Upside Potential PUD PD TEV4 5
Appendix
2Q-23 & FY-23 Guidance 1Current NGL composition C2 (42%), C3 (33%), IC4 (3%), NC4 (11%) and C5+ (11%) 11 Guidance Commodity Prices Used for 2Q-23 2Q-23 Avg.Jun-23May-23Apr-23 Crude Oil: $73.94$71.18$71.28$79.44WTI NYMEX ($/BBO) $77.87$75.08$75.21$83.41Brent ICE ($/BBO) Natural Gas: $2.08$2.14$2.12$1.99Henry Hub ($/MMBTU) $0.70$0.92$1.09$0.09Waha ($/MMBTU) Natural Gas Liquids: $8.44$8.14$8.35$8.84C2 ($/BBL) $30.29$29.09$27.96$33.91C3 ($/BBL) $36.91$34.44$33.23$43.18IC4 ($/BBL) $35.04$32.87$32.17$40.17NC4 ($/BBL) $61.48$58.07$60.10$66.32C5+ ($/BBL) $25.27$24.05$23.88$27.91Composite ($/BBL)1 FY-232Q-23 Production: 76.0 - 80.085.5 - 88.5Total Production (MBOE/D) 36.3 - 39.340.0 - 43.0Crude Oil Production (MBO/D) $625 - $675$155 - $175Incurred Capital Expenditures ($MM): Average Sales Price Realizations (excluding derivatives): -101%Crude Oil (% of WTI) -18%Natural Gas Liquids (% of WTI) -27%Natural Gas (% of Henry Hub) Net Settlements Received (Paid) for Matured Commodity Derivatives ($MM): -$1Crude Oil ($MM) --Natural Gas Liquids ($MM) -$12Natural Gas ($MM) Operating Costs and Expenses ($/BOE): -$7.50Lease Operating Expenses -7.00%Production and Ad Valorem Taxes (% of Oil, NGL & Natural Gas Revenues) -$1.40Transportation and Marketing Expenses -$2.50General and Administrative Expenses (excluding LTIP & Transaction Expense) -$0.15General and Administrative Expenses (LTIP Cash) -$0.35General and Administrative Expenses (LTIP Non-Cash) -$12.75Depletion, Depreciation and Amortization
65% 55% 47% 63% 0% 50% 100% 2H-23 2Q-23 2H-23 2Q-23 Hedge Book Structured to Maintain Exposure to Higher Prices 1Hedges executed as of May 5, 2023; 2Calculated using guidance mid-point 12 FY-244Q-243Q-242Q-241Q-24FY-234Q-233Q-232Q-23 76171819211,287552552183WTI Swaps C ru d e O il (V o lu m e M B O ; P ri ce $ /B B L) $63.75$63.75$63.75$63.75$63.75$74.27$73.39$73.39$79.62Price -----3,8858919032,092WTI Collars -----$68.75 $69.60 $69.55$68.04 Bought Put -----$85.45 $87.04 $86.98 $84.10 Sold Call 2174952566130192100110WTI Three-Way Collars $50.00 $50.00 $50.00 $50.00$50.00$45.58$45.50$45.59$45.64 Sold Put $66.51$66.45$66.47$66.50$66.57$57.71$57.64$57.72$57.76Bought Put $87.09 $87.05 $87.06 $87.09 $87.14$74.45 $74.25 $74.48$74.58 Sold Call 29366707582458154175129WTI Midland Basis Swaps $0.11$0.12$0.11$0.11$0.11$0.18$0.17$0.18$0.18Price 455,700118,250122,600105,350109,500120,50038,00040,10042,400 Henry Hub Swaps N at u ra l G as ( V o lu m e M M B TU ; P ri ce $ /M M B TU ) $3.29$3.28$3.28$3.30$3.30$2.46$2.46$2.46$2.46Price 776,292149,511169,320214,333243,12820,377,996 6,826,5346,858,8736,692,589 Henry Hub Collars $3.40$3.40$3.44$3.36$3.40$4.11$4.11$4.11$4.11WTD Floor Price $6.11$6.12$6.22$6.00$6.11$8.32 $8.34 $8.33$8.31 WTD Ceiling Price -----140,50033,50035,50071,500Henry Hub Three-Way Collars -----$2.00$2.00$2.00$2.00Sold Put -----$2.50$2.50$2.50$2.50Bought Put -----$3.01$3.01$3.01$3.01Sold Call 4,891,9921,187,7611,211,9201,229,6831,262,62831,638,99610,578,03410,614,47310,446,489Waha Basis Swaps ($0.82)($0.81)($0.82)($0.82)($0.83)($1.53)($1.53)($1.53)($1.53)Price Volumes Hedged2 Crude Oil Natural Gas
Free Cash Flow Driving Return of Capital and Debt Reductions 1As of May 5, 2023 13 Current Debt Maturity Profile1 $456 $255 $745 $298$300 2023 2024 2025 2026 2027 2028 2029 $1.3 billion Borrowing Base (Credit Facility) $1.0 billion Elected Commitments (Credit Facility) $68 million Current Cash Balance1 $813 million Current Liquidity1 9.500% Sr. Notes 2025 10.125% Sr. Notes 2028 7.750% Sr. Notes 2029 Drawn Credit Facility Undrawn Credit Facility
0 25 50 75 100 125 150 175 200 0 60 120 180 240 300 360 C u m u la ti ve G ro ss O il P ro d u ct io n p e r W e ll (M B O ) Producing Days 28%, WC-A 74%, WC-A 35%, LSS 26%, LSS 37%, MS 92 23 N. Howard C. Howard Howard County Development Program 1Gross operated locations as of January 2023 ; 2Production data normalized for 10,000’ lateral length and downtime 14 Development Average Well Performance2 Primary Development Targets VTLE Net Acres Howard North Central Inventory Locations1 LS DEAN MS LSS WC-A JO MILL N. Howard (WC-A / LSS / MS) C. Howard (WC-A / LSS) ~85%~95%Avg. WI ~10,250’~11,000’Avg. LL
0 25 50 75 100 125 150 0 60 120 180 240 300 360 C u m u la ti ve G ro ss O il P ro d u ct io n p e r W e ll (M B O ) Producing Days W. Glasscock County Development Program 1Gross operated locations as of January 2023 ; 2Production data normalized for 10,000’ lateral length and downtime 15 Development Area Average Well Performance2 Primary Development Targets Glasscock Inventory Locations1 DEAN WC-B – Potential Upside Target LSS WC-A WC-D WC-C – Potential Upside Target 46%, WC-D 32%, WC-A 22%, LSS ~295 W. Glasscock ~90%Avg. WI ~11,500’Avg. LL W. Glasscock (WC-A / LSS / WC-D) W. Glasscock VTLE Net Acres
0 25 50 75 100 125 150 175 0 60 120 180 240 300 360 C u m u la ti ve G ro ss O il P ro d u ct io n p e r W e ll (M B O ) Producing Days Upton / S. Reagan County Development Program 1Gross operated locations as of January 2023 ; 2Production data normalized for 10,000’ lateral length and downtime 16 Development Area Average Well Performance2 Primary Development Targets Reagan Inventory Locations1 DEAN WC-B 100%, WC-B ~30 Upton / S. Reagan ~75%Avg. WI ~10,000’Avg. LL Upton / S. Reagan (WC-B) LSS – Potential Upside Target WC-A – Potential Upside Target WC-C UPPER LOWER Upton VTLE Net Acres Upton / S. Reagan
0 25 50 75 100 125 150 0 60 120 180 240 300 360 C u m u la ti ve G ro ss O il P ro d u ct io n p e r W e ll (M B O ) Producing Days Wolfcamp D in Glasscock County Extends Oil-Weighted Inventory 1Production data normalized for 10,000’ lateral length, downtime and completion design > 1,500 #/ft 17 Average Well Performance by Completion Design1 Wolfcamp D Producing Wells W. Glasscock E. Glasscock Organically added ~80 oil-weighted Wolfcamp D locations in Glasscock County VTLE W. Glasscock > 1,500 #/ft VTLE E. Glasscock > 1,500 #/ft VTLE < 1,500 #/ft VTLE Leasehold VTLE W. Glasscock > 1,500 #/ft VTLE E. Glasscock > 1,500 #/ft VTLE < 1,500 #/ft Industry Activity
Proved Reserves Underpin Company Value 1Based only on wells categorized as Proved Developed as of YE-22 and decline calculated 4Q to 4Q 18 Proved Reserves Components | YE-22 Annual Base Production Decline Expecatations1 Total Proved Reserves | MMBOE PD 74% PUD 26% FY-25FY-24FY-23 23%33%46% Oil, MBO/d Howard 19%27%41%Total Company 22%31%41% Total Production, MBOE/d Howard 15%20%29%Total Company Oil 39% NGL 31% Natural Gas 30% 319 302 17 (4) (30) YE-21 Revisions & Extensions Sale Of Reserves 2022 Production YE-22
Supplemental Non-GAAP Financial Measures 1Includes capitalized share-settled equity-based compensation and asset retirement costs 19 Free Cash Flow Free Cash Flow is a non-GAAP financial measure that the Company defines as net cash provided by operating activities (GAAP) before net changes in operating assets and liabilities and non-budgeted acquisition costs, less incurred capital expenditures, excluding non-budgeted acquisition costs. Management believes 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 Free Cash Flow as a measure of performance, including the lack of comparability due to the different methods of calculating Free Cash Flow reported by different companies. The following table presents a reconciliation of net cash provided by operating activities (GAAP) to Free Cash Flow (non-GAAP) for the periods presented: Three Months Ended March 31, 20222023(in thousands, unaudited) $170,882$116,125Net cash provided by operating activities Less: (23,224)(66,756)Net changes in operating assets and liabilities —(861)General and administrative (transaction expenses) 194,106183,742Cash flows from operating activities before changes in operating assets and liabilities and non-budgeted acquisition costs Less incurred capital expenditures, excluding non-budgeted acquisition costs: 168,368184,114Oil and natural gas properties(1) 2,5313,530Midstream and other fixed assets(1) 170,899187,644Total incurred capital expenditures, excluding non-budgeted acquisition costs $23,207($3,902) Free Cash Flow (non-GAAP)
Supplemental Non-GAAP Financial Measures 20 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, 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 widely 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 2022 Annual Report 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 Tenth Amendment to the Senior Secured Credit Facility, as filed with the SEC on November 3, 2022.
Supplemental Non-GAAP Financial Measures 1 Calculation conforms to credit facility covenant which requires various treatment of asset transaction impacts 21 Consolidated EBITDAX The following table presents a reconciliation of net income (loss) (GAAP) to Consolidated EBITDAX (non-GAAP) for the periods presented: Trailing Twelve Months ended March 31, Three Months Ended March 31, 202320222023(in thousands, unaudited) $832,233($86,781)$113,940Net income (loss) Plus: 8,9222,0532,572Share-settled equity-based compensation 324,92773,49286,779Depletion, depreciation and amortization 40——Impairment expense 10,420——Organizational restructuring expenses 582260(237)(Gain) loss on disposal of assets, net Mark-to-market on derivatives: (47,583)325,816(20,490)(Gain) loss on derivatives, net (363,146)(125,370)(1,763)Settlements paid for matured derivatives, net 3,912—1,455Settlements received for contingent consideration 3,7591,019899Accretion expense 121,19832,47728,554Interest expense 1,459——Loss on extinguishment of debt, net 7,986(877)1,607Income tax (benefit) expense 861—861General and administrative (transaction expenses) $905,570$222,089$214,177Consolidated EBITDAX (non-GAAP) (21,562)Transaction adjustments (Senior Secured Credit Facility covenant compliance)1 $884,008Consolidated EBITDAX (non-GAAP) (Senior Secured Credit Facility covenant compliance)1
Supplemental Non-GAAP Financial Measures 22 Consolidated EBITDAX The following table presents a reconciliation of net cash provided by operating activities (GAAP) to Consolidated EBITDAX (non-GAAP) for the periods presented: Three Months Ended March 31, 20222023(in thousands, unaudited) $170,882$116,125Net cash provided by operating activities Plus: 32,47728,554Interest expense 1,2181,331Current income tax expense 23,22466,756Net changes in operating assets and liabilities —861General and administrative (transaction expenses) —1,455Settlements received for contingent consideration (5,712)(905)Other, net $222,089$214,177Consolidated EBITDAX (non-GAAP)
Supplemental Non-GAAP Financial Measures 23 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 $50 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. Net Debt to Consolidated EBITDAX Net Debt to Consolidated EBITDAX, a non-GAAP financial measure, is calculated as Net Debt divided by Consolidated EBITDAX, for the previous four quarters, as defined in the Company's Senior Secured Credit Facility. Net Debt to Consolidated EBITDAX is used by the Company’s management for various purposes, including as a measure of operating performance, in presentations to its board of directors and as a basis for strategic planning and forecasting. As of March 31, 20222023(in thousands, unaudited) $1,338,957$1,054,151Total senior unsecured notes 100,000120,000Senior Secured Credit Facility 44,115—Letters of credit 1,483,0721,174,151Total long-term debt Less: 50,00027,682Cash and cash equivalents $1,433,072$1,146,469Net Debt (non-GAAP)
Supplemental Non-GAAP Financial Measures 24 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. December 31, 2022(in millions) $4,755Standardized measure of discounted future net cash flows (709) Less present value of future income taxes discounted at 10% $5,464 PV-10 (non-GAAP)