1Q-22 Earnings Presentation EXHIBIT 99.2
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 Laredo Petroleum, Inc. (together with its subsidiaries, the “Company”, “Laredo” or “LPI”) 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 Laredo include, but are not limited to, 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, 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, oil production quotas or other actions that might be imposed by the Organization of Petroleum Exporting Countries and other producing countries (“OPEC+”), the outbreak of disease, such as the coronavirus (“COVID-19”) pandemic, and any related government policies and actions, changes in domestic and global production, supply and demand for commodities, including as a result of the COVID-19 pandemic, actions by OPEC+ and the Russian-Ukrainian military conflict, long-term performance of wells, drilling and operating risks, the increase in service and supply costs, including as a result of inflationary pressures, tariffs on steel, pipeline transportation and storage constraints in the Permian Basin, the possibility of production curtailment, hedging activities, 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 laws and regulations, including those regarding the use of hydraulic fracturing, 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, 2021, and those set forth from time to time in other filings with the Securities and Exchange Commission (“SEC”). These documents are available through Laredo’s website at www.laredopetro.com under the tab “Investor Relations” or through the SEC’s Electronic Data Gathering and Analysis Retrieval System at www.sec.gov. Any of these factors could cause Laredo’s actual results and plans to differ materially from those in the forward-looking statements. Therefore, Laredo can give no assurance that its future results will be as estimated. Any forward-looking statement speaks only as of the date on which such statement is made. Laredo 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 Consolidated EBITDAX and Free Cash Flow. 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. 2 Forward-Looking / Cautionary Statements
Optimize Capital Structure Targeting leverage of <1.5x by 3Q-22 and <1.0x by 1Q-23 Utilize FCF4 to reduce debt by ~$300 million in 2022 Maintain strong liquidity profile Improve cost of capital Return of capital to shareholders YE-21 Reserves 319 MMBOE (~38% Oil) $3.7B PV-103 Enterprise Value Market Capitalization1 $2.5 Billion $1.2 Billion (17.3mm Shares) Laredo Petroleum (NYSE: LPI) | Pure-Play Permian Energy Producer 1As of market close 3/29/2022; 2Assumes current activity pace; 3Assumes SEC pricing of $63 WTI oil & $3.35 HH gas 4See Appendix for definitions of non-GAAP financial measures Acreage FootprintCompany Snapshot Corporate Principles Driving Shareholder Value Net Acres | Years of Inventory2 ~166,000 ~8 Years Q1-22A Production 85.1 MBOE/D ~47% Oil Net Debt to Consolidated EBITDAX4 2.1x <1.5x YE-21A 3Q-22E Scope 1 Emissions mtCO2e/MBOE 17.5 12.5 2020A 2025 Target Leasehold Acreage Glasscock Howard Reagan Martin Midland Upton Sterling Irion Mitchell Dawson Borden TX Maximize Free Cash Flow4 High grade development to maximize capital efficiency Commodity mix improvement Focus on efficiencies and low-cost operations Disciplined hedge program Build scale through accretive transactions Advance Sustainability Formalized Board of Directors ESG oversight Meaningful emissions reduction targets Pay linked to performance ESG reporting aligned to industry- standard frameworks Diversity transparency via EEO-1 data disclosure 3
$1.2 Equity $1.5 Equity $1.3 Debt $1.0 Debt Current ProForma 2.7x 2.1x ≤1.5x YE-20A YE-21A 3Q-22E 31% 39% ~49% FY-20A FY-21A FY-22E 1See Appendix for definitions of non-GAAP financial measures; 2Assumes WTI oil price of $97 and HH gas price of $6.55; 3Based on 17.3 million shares outstanding Strong Value Creation Built on Disciplined Strategy 4 RETURN OF CAPITAL TO SHAREHOLDERS DISCIPLINED EXECUTION OF STRATEGY UNDERPINS VALUE CREATION FREE CASH FLOW1 EXPANSION 2019 - 2021 2022 2023+ GREW INVENTORY SHIFTED COMMODITY MIX REDUCED LEVERAGE FREE CASH FLOW1 GENERATION ACCELERATE LEVERAGE REDUCTION RETURN OF CAPITAL TO SHAREHOLDERS FREE CASH FLOW1 EXPANSION Acceleration of Value through Accretive Transactions MAINTENANCE CAPITAL Shifting Production Mix Improving Leverage Ratio1,2 Shifting Value to Shareholders through Debt Reduction Oil Production % of Total Production Net Debt-to-Consolidated EBITDAX Total Enterprise Value, $B$2.5B $2.5B $300 million of debt reduction Equal to ~$17 per share3
100 125 130 165 165 60 195 275 295 295 ≤$40 ≤$45 ≤$50 ≤$55 Inventory Upside Near-term Development Focus 1Gross operated location as of January 2022 (adjusted for 2021 completions) 2Locations may require the formation of drilling units to develop 3Flat oil price needed to achieve 10% IRR assuming gas price at 20:1 ratio Development Focus Areas ~460 ~320 ~1502 Avg. Breakeven Oil Price3 ~8 Years of Inventory1 Assumes: Current activity pace Low-risk, operated only Current development spacing <$55 breakeven oil price Howard Glasscock Howard W. Glasscock Eastern Reagan Midland Martin Sterling Mitchell ~160 Low Breakeven Oil Inventory Underpins Sustainable Free Cash Flow Generation 5 ~405 Howard W. Glasscock Eastern
0 25 50 75 100 125 150 175 200 0 90 180 270 360 C u m u la ti v e G ro s s O il P ro d u c ti o n p e r W e ll ( M B O ) Producing Days 0 20 40 60 80 100 120 0 30 60 90 120 150 C u m u la ti v e G ro s s O il P ro d u c ti o n p e r W e ll ( M B O ) Producing Days 1Gross operated location as of January 2022 (adjusted for 2021 completions); 2Production data normalized to 10,000’ lateral length, downtime days excluded Howard County Inventory and Well Performance Avg. LSS/WCA Well Performance2 Howard Borden North Howard Central Howard Middle Spraberry Performance2 Net Acres ~33,000 Q1-22A Net Production (MBOE/D) | % Oil 35.8 | 72% LSS / WCA Locations1 ~130 MS Locations1 ~35 Total Development Locations1 ~165 Avg. Lateral Length (ft.) ~11,500’ Avg. WI (%) ~92% Highlights 2022 development program entirely focused on Howard County Consolidated acreage position facilitates drilling of more capital efficient longer laterals Integrating eight Middle Spraberry wells into the 2022 development plan Thumper D 4MS Thumper B 2MS North Howard Central Howard (Wider-Spacing) Central Howard (Tighter-Spacing) Howard - Key Stats and Acreage Position 6
0 10 20 30 40 50 60 70 80 0 25 50 75 100 125 C u m u la ti v e G ro s s O il P ro d u c ti o n p e r W e ll ( M B O ) Producing Days 0 25 50 75 100 125 150 0 90 180 270 360 C u m u la ti v e G ro s s O il P ro d u c ti o n p e r W e ll ( M B O ) Producing Days Cook Package Books Package Glasscock Reagan W. Glasscock Eastern W. Glasscock County Inventory and Well Performance Avg. LSS/WCA/WCB Well Performance2 Wolfcamp D Performance2 Net Acres ~33,000 Q1-22A Net Production (MBOE/D) | % Oil 12.7 | 62% LSS / WCA / WCB Locations1 ~205 WCD Locations1 ~90 Total Development Locations1 ~295 Avg. Lateral Length (ft.) ~10,500’ Avg. WI (%) ~88% Highlights Completed a 10-well package in 4Q-21, including two Wolfcamp D appraisal wells Successful Wolfcamp D appraisal drilling unlocked ~90 locations, driven by optimized completion design 2024 development plan expected to focus on western Glasscock County Optimized Wolfcamp D Completion Design Historical Wolfcamp D Average W. Glasscock - Key Stats and Acreage Position 7 1Gross operated location as of January 2022 (adjusted for 2021 completions); 2Production data normalized to 10,000’ lateral length, downtime days excluded
~$910 ~$965 ~$1,025 ~$1,080 $80 $90 $100 $110 81% 8% 7% 4% 1,117 1,314 1,439 1,539 1,274 1,408 1,653 1,572 FY-19A FY-20A FY-21A YTD-22A Drilling Ft./Day/Rig Fractured Ft./Day/Crew 6 15 15 12 6 18 7 15 15 1Q-22A 2Q-22E 3Q-22E 4Q-22E N. Howard C. Howard Drilling & Completion Efficiencies Disciplined, Efficient Capital Program Maintains Prior Year Activity Levels 2022E Capital Program FY-22 Guidance Capital Expenditures ($MM) ~$550 Avg. Rig Count (Op) ~2.3 Avg. Frac Crews (Op) ~1.2 Spuds 65 Gross (62.9 Net) Completions 55 Gross (53.1 Net) Turn-in-Lines 55 Gross (53.1 Net) Production (MBOE/d) 82.0 – 86.0 Oil Production (MBO/d) 39.5 – 42.5 Capital Expenditures by Category DC&E (op) Facilities & Land Corporate DC&E (non-op) 8 Benchmark WTI Oil Price (per BBL) (Benchmark HH Gas Price assumes $6.55/mcf) 2022E Operated Turn-in-Line Well Count 2022E Consolidated EBITDAX1 Sensitivity - $MM 10,750' 9,950' 10,000' 11,800' FY-19A FY-20A FY-21A FY-22E FY-19A FY-20A FY-21A FY-22E Avg. Completed Lateral Length 1See Appendix for definitions of non-GAAP financial measures
~70% ~45% ~70% Natural Gas Natural Gas Liquids Crude Oil 2.7x 2.1x ≤1.5x ≤1.0x YE-20A YE-21A 3Q-22E 1Q-23E $578 $361 $400 $50 $44 $906 2022 2023 2024 2025 2026 2028 2029 1As of 5/3/2022; 2See Appendix for definitions of non-GAAP financial measures; 3Assumes WTI oil price of $97 and HH gas price of $6.55 for 2022 and WTI oil price of $85 and HH gas price of $5.15 for 2023; 4Calculated using guidance mid-point Free Cash Flow Supports Debt Reduction Net Debt to Consolidated EBITDAX2,3 Current Debt Maturity Profile1Q2-22E to Q4-22E Volumes Hedged4 Borrowing Base $1,250 MM Elected Commitment $1,000 MM Cash Balance $104 MM Liquidity ~$1,010 MM 9.500% Sr. Notes 2025 10.125% Sr. Notes 2028 7.750% Sr. Notes 2029 Drawn Credit Facility Outstanding Letters of Credit Undrawn Credit Facility 9 2022 Debt Reduction Target ~$300 million Current Liquidity1 ~$1.01 billion 3Q-22E Net Debt to Consolidated EBITDAX2,3 <1.5x Target 1Q-23E Net Debt to Consolidated EBITDAX2,3 <1.0x Target
1.95% 0.71% 0.37% 0.64% 0.78% FY-19A FY-20A FY-21A YTD-22A Zero routine flaring 10 <12.5 mtCO2e / MBOE <0.20% methane emissions1,2 18.08 17.54 12.50 2019 Baseline 2020 Performance Venting Reductions Flaring Reductions Pnuematics Reductions Combustion Reductions 2025 Target S c o p e 1 E m is s io n s m tC O 2 e / M B O E Defined Scope 1 Emissions Reduction Plan Systematic Plan to Achieve Emissions Reductions TrustWellTM Certification First Permian operator to receive TrustWellTM responsibly sourced certification Gold certification awarded for production from 73 horizontal wells representing ~31,500 BOEPD of gross operated production in the certification area Uniquely positioned among Permian Basin operators to benefit as premium markets are developed for certified responsibly sourced production Targets for 2025 12019 calendar year as baseline; 2As a percentage of natural gas production Percentage of Produced Natural Gas Flared / Vented Acquisitions Impact eu i
1Data as of 12/31/2021 Corporate and Community Responsibility Local and Impactful Philanthropy >$820,000 Total amount donated since 2019 to improve our local communities1 Diversity and Inclusion Efforts1 EEO-1 Data Disclosed in Company’s 2021 ESG & Climate Risk Report 27% 26% 61% 56% Women in Workforce Minorities in Workforce Women and/or Minorities in Professional-or-higher Roles Female and Minority Directors 11
Appendix
2Q-22 & FY-22 GUIDANCE Guidance Commodity Prices Used for 2Q-22 Apr-22 May-22 Jun-22 2Q-22 Avg. Crude Oil: - - - - WTI NYMEX ($/BBO) $101.64 $104.19 $102.25 $102.71 Brent ICE ($/BBO) $105.81 $107.06 $105.36 $106.09 Natural Gas: - - - - Henry Hub ($/MMBTU) $5.34 $7.27 $7.24 $6.62 Waha ($/MMBTU) $4.48 $6.11 $6.36 $5.66 Natural Gas Liquids: - - - - C2 ($/BBL) $21.37 $22.47 $22.47 $22.11 C3 ($/BBL) $54.30 $54.02 $54.08 $54.13 IC4 ($/BBL) $69.71 $72.45 $70.04 $70.75 NC4 ($/BBL) $65.41 $67.88 $66.31 $66.55 C5+ ($/BBL) $95.12 $95.34 $94.76 $95.08 Composite ($/BBL)1 $46.65 $47.39 $47.10 $47.05 2Q-22 FY-22 Production: - - Total Production (MBOE/D) 85.0 – 88.0 82.0 – 86.0 Crude Oil Production (MBO/d) 40.0 – 42.0 39.5 – 42.5 Incurred Capital Expenditures ($MM): ~$125 ~$550 Average Sales Price Realizations (excluding derivatives): - - Crude Oil (% of WTI) 100% - Natural Gas Liquids (% of WTI) 34% - Natural Gas (% of Henry Hub) 68% - Net Settlements Received (Paid) for Matured Commodity Derivatives ($MM): - - Crude Oil ($MM) ($119) - Natural Gas Liquids ($MM) ($16) - Natural Gas ($MM) ($20) - Net Income (Expense) of Purchased Oil ($MM): $0 - Operating Costs & Expenses ($/BOE): - - Lease Operating Expenses $5.35 - Production & Ad Valorem Taxes (% of Oil, NGL & Natural Gas Revenues) 6.5% - Transportation and Marketing Expenses $1.65 - General and Administrative Expenses (excluding LTIP) $1.65 - General and Administrative Expenses (LTIP Cash) $0.45 - General and Administrative Expenses (LTIP Non-Cash) $0.25 - Depletion, Depreciation and Amortization $9.75 - Note: Supports average sales price realization and derivatives guidance 13 1Current NGL composition C2 (42%), C3 (33%), IC4 (3%), NC4 (11%) and C5+ (11%)
Crude Oil Hedge Book1 (Volume in MBO; Price in $/BBO) Q2-22 Q3-22 Q4-22 BAL-22 Q1-23 Q2-23 Q3-23 Q4-23 FY-23 Brent Swaps 1,028 1,040 1,040 3,108 - - - - - WTD Price $48.34 $48.34 $48.34 $48.34 - - - - - Brent Collars 387 391 391 1,169 - - - - - WTD Floor Price $56.65 $56.65 $56.65 $56.65 - - - - - WTD Ceiling Price $65.44 $65.44 $65.44 $65.44 - - - - - WTI Swaps 884 92 92 1,068 - - - - - WTD Price $85.14 $64.40 $64.40 $81.57 - - - - - WTI Collars 846 856 856 2,558 1,530 1,547 460 460 3,997 WTD Floor Price $58.23 $58.23 $58.23 $58.23 $66.18 $66.18 $67.00 $67.00 $66.37 WTD Ceiling Price $69.39 $69.39 $69.39 $69.39 $80.29 $80.29 $84.04 $84.04 $81.16 Total Swaps/Collars 3,145 2,378 2,378 7,902 1,530 1,547 460 460 3,997 WTD Floor Price $62.36 $53.88 $53.88 $57.26 $66.18 $66.18 $67.00 $67.00 $66.37 Natural Gas Liquids Hedge Book1 (Volume in MBBL; Price in $/BBL) Q2-22 Q3-22 Q4-22 BAL-22 Q1-23 Q2-23 Q3-23 Q4-23 FY-23 Ethane Swaps 382 386 386 1,155 - - - - - WTD Price $11.42 $11.42 $11.42 $11.42 - - - - - Propane Swaps 291 294 294 880 - - - - - WTD Price $35.91 $35.91 $35.91 $35.91 - - - - - Butane Swaps 91 92 92 275 - - - - - WTD Price $41.58 $41.58 $41.58 $41.58 - - - - - Isobutane Swaps 27 28 28 83 - - - - - WTD Price $42.00 $42.00 $42.00 $42.00 - - - - - Pentane Swaps 91 92 92 275 - - - - - WTD Price $60.65 $60.65 $60.65 $60.65 - - - - - Natural Gas Hedge Book1 (Volume in MMBTU; Price in $/MMBTU) Q2-22 Q3-22 Q4-22 BAL-22 Q1-23 Q2-23 Q3-23 Q4-23 FY-23 Henry Hub Swaps 910,000 920,000 920,000 2,750,000 - - - - - WTD Price $2.73 $2.73 $2.73 $2.73 - - - - - Henry Hub Collars 7,280,000 7,360,000 7,360,000 22,000,000 3,600,000 3,640,000 3,680,000 3,680,000 14,600,000 WTD Floor Price $3.09 $3.09 $3.09 $3.09 $3.75 $3.75 $3.75 $3.75 $3.75 WTD Ceiling Price $3.84 $3.84 $3.84 $3.84 $7.88 $7.88 $7.88 $7.88 $7.88 Total Henry Hub Swaps/Collars 8,190,000 8,280,000 8,280,000 24,750,000 3,600,000 3,640,000 3,680,000 3,680,000 14,600,000 WTD Floor Price $3.05 $3.05 $3.05 $3.05 $3.75 $3.75 $3.75 $3.75 $3.75 Waha Basis Swaps 7,234,500 7,314,000 7,314,000 21,862,500 3,600,000 3,640,000 3,680,000 3,680,000 14,600,000 WTD Price ($0.36) ($0.36) ($0.36) ($0.36) ($1.52) ($1.52) ($1.52) ($1.52) ($1.52) 1Hedges executed as of 5/3/2022 Active Hedge Program to Protect Free Cash Flow 14
$3,716 $3,154 $3,902 $4,649 $5,398 SEC Pricing $55 $65 $75 $85Oil 38% NGL 31% Natural Gas 31% PD, 73% PUD, 27% 1SEC pricing $63 benchmark oil and $3.35 benchmark gas; 2Based only on wells categorized as Proved Developed as of YE-21 and decline calculated Q4 to Q4; 3 See Appendix for definitions of non-GAAP financial measures Oil Reserve Growth Driven by Strategic Portfolio Repositioning Highlights Proved reserves PV-103 improved by ~260% versus YE-20 Strategic acquisitions increased oil reserves by ~65 MMBLs, offset by the sale of 16 MBBLs, leading to an improved oil production mix PUD reserves improved driven by inventory depth and price resiliency PV-103 Reserve Value Sensitivity - $MM1 278 58 (88) 100 (30) 319 YE2020 Revisions & Extensions Sale of Reserves Purchase of Reserves 2021 Production YE2021 78% Oil Growth24% Oil 38% Oil Total Reserves and Resources - MMBOE Benchmark WTI Oil Price (Benchmark HH Gas Price assumes $3.50) Reserves by Category Annual Base Production Decline Expectations2 Reserves by Commodity FY-22 FY-23 FY-24 Howard Oil, MBO/d 57% 34% 24% Total Company 44% 29% 20% Howard Total Production, MBOE/d 53% 32% 23% Total Company 30% 20% 15% 15
Supplemental Non-GAAP Financial Measures Consolidated EBITDAX (Unaudited) 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 extraordinary gains (or losses), non-cash recurring gains (or losses), depletion, depreciation and amortization expense, interest expense, any provisions for (or benefit from) income or franchise taxes, exploration expenses and other non-cash charges. Consolidated EBITDAX is used by the Company’s management for various purposes, including as a measure of operating performance and compliance under the Company’s Senior Secured Credit Facility. Additional information on the calculation of Consolidate EBITDAX can be found in the Company’s Eighth Amendment to the Senior Secured Credit Facility as filed with the SEC on April 19, 2022. The following table presents a reconciliation of net income (loss) (GAAP) to Consolidated EBITDAX (non-GAAP) for the periods presented: 16 (in thousands, unaudited) 3/31/2022 12/31/2021 9/30/2021 Net Income (loss) ($86,781) $216,276 $136,832 Plus: Share-settled equity-based compensation, net 2,053 2,066 1,811 Depletion, depreciation and amortization 73,492 74,592 62,678 Mark-to-market on derivatives: (Gain) loss on derivatives, net 325,816 (15,372) 96,240 Settlements paid for matured derivatives, net (125,370) (129,361) (92,726) Accretion expense 1,019 1,026 906 Gain on sale of oil and natural gas properties, net - - (95,223) Loss on disposal of assets, net 260 8,903 22 Interest expense 32,477 31,163 30,406 Income tax (benefit) expense (877) 3,052 2,677 Consolidated EBITDAX (non-GAAP) $222,089 $192,345 $143,623 Three months ended,
Supplemental Non-GAAP Financial Measures PV-10 (Unaudited) 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. 17 (in millions) December 31, 2021 Standardized measure of discounted future net cash flows $3,425 Less present value of future income taxes discounted at 10% (291) PV-10 (non-GAAP) $3,716
Supplemental Non-GAAP Financial Measures Net Debt (Unaudited) Net Debt, a non-GAAP financial measure, is calculated as the face value of long-term debt plus any outstanding letters of credit, less cash and cash equivalents. 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 as of March 31, 2022 was $1.418 billion. Net Debt to Consolidated EBITDAX (Unaudited) Net Debt to Consolidated EBITDAX, a non-GAAP financial measure, is calculated as Net Debt, including letters of credit, divided by Consolidated EBITDAX, as defined in the Company's Senior Secured Credit Facility. For the purposes of calculating Consolidated EBITDAX for the period ended March 31, 2022 calculation is the annualization of the three quarters ended March 31, 2022. 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. Free Cash Flow (Unaudited) Free Cash Flow is a non-GAAP financial measure that the Company defines as net cash provided by operating activities (GAAP) before changes in operating assets and liabilities, net, less incurred capital expenditures, excluding non-budgeted acquisition costs. Free Cash Flow does not represent funds available for future discretionary use because it excludes funds required for future debt service, capital expenditures, acquisitions, working capital, income taxes, franchise taxes and other commitments and obligations. However, 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 Company is unable to provide a reconciliation of the forward-looking Free Cash Flow projection contained in this presentation to net cash provided by operating activities, the most directly comparable GAAP financial measure, because we cannot reliably predict certain of the necessary components of net cash provided by operating activities, such as changes in working capital, without unreasonable efforts. Such unavailable reconciling information may be significant. 18
