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): December 5, 2022
(Exact name of registrant as specified in charter)
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Registrant’s telephone number, including area code: (918 ) 513-4570
Not Applicable
(Former name or former address, if changed since last report)
Securities registered pursuant to Section 12(b) of the Exchange Act:
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Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
| Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) | |||||||||||
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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 Exchange Act. ☐ | |||||||||||
Item 7.01. Regulation FD Disclosure.
On December 5, 2022, Laredo Petroleum, Inc. (the "Company") posted to its website an investor presentation (the "Presentation"), including the below updates related to fourth-quarter 2022:
•4Q-22 average daily oil production currently above the high end of guidance range (32-34 MBO/d)
•4Q-22 average daily total production currently above the high end of guidance range (72.5-75.5 MBOE/d)
•4Q-22 capital investments expected to be within guidance range of $135-$145 million
•Repurchased approximately $100 million of face value of term debt quarter-to-date
•Repurchased approximately $11 million of equity quarter-to-date
•Announced rebranding of Company to Vital Energy
The Presentation is available on the Company's website, www.laredopetro.com, and is attached hereto as Exhibit 99.1 and incorporated into this Item 7.01 by reference.
All statements in the Presentation, other than historical financial information, may be deemed to be forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Exchange Act of 1934, as amended (the "Exchange Act"). Although the Company believes the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance, and actual results or developments may differ materially from those in the forward-looking statements. See the Company's Annual Report on Form 10-K for the year ended December 31, 2021 and the Company's other filings with the Securities and Exchange Commission for a discussion of other risks and uncertainties. The Company disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
In accordance with General Instruction B.2 of Form 8-K, the information furnished under this Item 7.01 of this Current Report on Form 8-K and the exhibit attached hereto are deemed to be "furnished" and shall not be deemed "filed" for the purpose of Section 18 of the Exchange Act, or otherwise subject to the liabilities of that section, nor shall such information be deemed incorporated by reference into any filing under the Securities Act or the Exchange Act.
Item 9.01. Financial Statements and Exhibits.
(d) Exhibits.
| Exhibit Number | Description | |||||||
| 104 | Cover Page Interactive Data File (formatted as Inline XBRL). | |||||||
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.
| LAREDO PETROLEUM, INC. | ||||||||
Date: December 5, 2022 | By: | /s/ Bryan J. Lemmerman | ||||||
| Bryan J. Lemmerman | ||||||||
| Senior Vice President and Chief Financial Officer | ||||||||
December 2022 Investor Presentation EXHIBIT 99.1
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, increases to interest rates as a result of the Federal Reserve’s tightening monetary policy, 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
3 Fourth-Quarter 2022 Updates 1As of December 2, 2022 Solid Fourth-Quarter ‘22 Execution 4Q-22 average daily oil production currently above high end of guidance range (32.0-34.0 MBO/d) 4Q-22 average daily total production currently above high end of guidance range (72.5-75.5 MBOE/d) 4Q-22 capital investments expected to be within guidance range ($135-$145 million) Continue to Strengthen Capital Structure Repurchased ~$100 million of face value of term debt QTD1 (~$285 million YTD1) Repurchased ~$11 million of equity QTD1 (~$37 million YTD1) Published ESG and Climate Risk Report Advancing key ESG initiatives across the enterprise Outlined aggressive methane reduction and water recycling targets; goals linked to NEO compensation Creating Value through Technology Intelligent well and ESP optimization digital initiatives benefitting base production Implementation of proprietary technologies Company rebrand in Jan ‘23
4 Disciplined Strategy Underpins Long-Term Value Creation Pure-Play Midland Basin Producer Howard Glasscock Reagan HOWARD ~33,000 net acres ~165 locations2 ~35.5 Mboe/d ~70% oil W. GLASSCOCK ~32,000 net acres ~295 locations2 ~8.8 Mboe/d ~55% oil EASTERN ~98,000 net acres ~150 upside locations3 ~35.3 Mboe/d ~15% oil TX Maintain Capital Discipline Generate Free Cash Flow1 Reduce Debt and Leverage Repurchase Shares Opportunistically Advance Sustainability and Responsible Production Oil-Weighted Leasehold Other Leasehold 1See Appendix for definitions of non-GAAP financial measures; 2Gross operated locations as of January 2022; 3Locations may require the formation of drilling units to develop
Enterprise Value $1.8 B $2.1 B1 +$0.3 B Net Acres ~133,500 ~163,000 +29,500 Oil Production 27.3 MBO/D 35.0 MBO/D2 +7.7 MBO/D Free Cash Flow4 $60 MM $183 MM3 +$123 MM Leverage Ratio 2.02x 1.25x2 -0.77x Net Debt per Share $96 $661 -$30 Liquidity ~$651 MM ~$955 MM1 +$304 MM Flaring Percentage 1.95% 0.74% -1.21% 5 Stronger Company Built on Strategic Execution 1As of December 2, 2022; 23Q-22A; 31Q-3QA; 4See Appendix for definitions of non-GAAP financial measures Key Metrics YE-19A YTD-22A CHANGE
$9 $18 $37 1Q-22A 2Q-22A 3Q-22A YTD-22A $32 $152 $285 1Q-22A 2Q-22A 3Q-22A YTD-22A 1.93x 1.39x 1.25x ~1.20x 1Q-22A 2Q-22A 3Q-22A 4Q-22E $23 $109 $51 $183 1Q-22A 2Q-22A 3Q-22A 1Q-3Q 22A 1See Appendix for definitions of non-GAAP financial measures; 2YTD-22A as of December 2, 2022 Delivering on Our Plan 6 Free Cash Flow1 (Units in $ millions) (Units in $ millions) Program Initiated 2Q-22 Program Initiated 2Q-22 Deleveraging Repurchasing Debt Repurchasing Shares (Units in $ millions @ Face Value) (Net Debt to Consolidated EBITDAX1 Multiple) 2 2
0 50 100 150 200 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 1Production data normalized for 10,000’ lateral length and downtime Well Performance After Offset Completions Current Development Plan Focused on Howard County 7 Average Well Performance1 North Howard Central Howard (2Q-21+) Central Howard (4Q-20 to 1Q-21) Leech (2Q-22) Howard Leasehold NORTH HOWARD Near-Term Development Program Focused in North Howard CENTRAL HOWARD LEECH DSU Martin Mitchell - 100 200 300 400 (120) (60) 0 0 60 120 G ro s s O il P ro d u c ti o n p e r W e ll ( B O /D ) Days Prior to Frac Days Post Frac Frac Impact Period (Varies) + Clean-Up Period (60 – 120 Days) Avg. Result of 34 Operated Wells in Howard County from 2019 to Current
83% 8% 9% 1,117' 1,314' 1,439' 1,567' FY-19A FY-20A FY-21A 1Q-3Q 22A 10,750' 9,950' 10,000' 12,012' FY-19A FY-20A FY-21A 1Q-3Q 22A 1,274' 1,408' 1,653' 1,612' FY-19A FY-20A FY-21A 1Q-3Q 22A ~4 Yrs. Current Sand Inventory2 Drilling Ft. Per Day Per Rig Disciplined, Capital Efficient Development Program 4Q-22E Capital Program Guidance Capital Expenditures ($MM) $135 - $145 Avg. Rig Count (Op) 2.0 Avg. Frac Crews (Op) 1.0 Completions 13 Gross (12.8 Net) Turn-in-Lines 11 Gross (10.8 Net) Production (MBOE/D) 72.5 – 75.5 Oil Production (MBO/D) 32.0 – 34.0 4Q-22E Capital Expenditures by Category DC&E (op) Facilities & Land Corporate 8 Continuous Improvement Drives Capital Efficient Drilling and Completion Program Company Owned Sand Mine Reduces Well Costs and Protects Against Inflation Avg. Completed Lateral Length 1Based on Howard County 10,000’ lateral length completions as of November 2, 2022; 2Based on current pace of development Fractured Ft. Per Day Per Crew Located on Laredo owned surface acreage Operated by a third party Reduces emissions by: − Elimination of truck traffic − Utilization of wet sand >$400K Per Well Savings1 Currently Above High-End of Guidance Range
$456 $300 $298 $80 $920 2022 2023 2024 2025 2026 2028 2029 $456 $300 $298 $122 $61 $102 $578 MM $361 MM $400 MM 9.500% Sr. Notes 2025 10.125% Sr. Notes 2028 7.750% Sr. Notes 2029 2.61x 2.14x 1.93x 1.39x 1.25x ~1.20x FY-20A FY-21A 1Q-22A 2Q-22A 3Q-22A 4Q-22E 1See Appendix for definitions of non-GAAP financial measures; 2Includes Sr. Notes; 3Assumes 4Q-22E WTI oil price / HH gas price of $86 / $6.15; 4As of December 2, 2022 Free Cash Flow Driving Return of Capital and Debt Reductions 9 Rapidly Deleveraging through Free Cash Flow1 Generation Current Debt Maturity Profile42022 Opportunistic Debt Repurchases Net Debt to Consolidated EBITDAX1,3 Borrowing Base $1,300 MM Elected Commitment $1,000 MM Cash Balance $34 MM Liquidity ~$955 MM 9.500% Sr. Notes 2025 10.125% Sr. Notes 2028 7.750% Sr. Notes 2029 Drawn Credit Facility Undrawn Credit Facility 1Q-3Q 22A Free Cash Flow1 $183 million Total Stock Repurchased4 YTD-22 $37 million Term Debt2,4 Reduced YTD-22 ~$285 million Current Liquidity4 ~$955 million Current Sr. Notes Balance4 Repurchased Sr. Notes
10 Leadership in a Low-Carbon Future OUR ENVIRONMENTAL TARGETS 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. <12.5 MTCO2e/MBOE SCOPE 1 GHG EMISSIONS INTENSITY BY 2025 ZERO ROUTINE FLARING BY 2025 <0.20% METHANE EMISSIONS BY 2025 (AS A PERCENT OF NATURAL GAS PRODUCTION) SCOPE 1 AND 2 GHG EMISSIONS INTENSITY < 10 MTCO2e/MBOE BY 2030 50% RECYCLED WATER FOR COMPLETION OPERATIONS BY 2025 CH4 2021 TO 2022 ESG PROGRESS 62% REDUCTION IN FLARING SINCE 2019 34% REDUCTION IN SCOPE 1 GHG EMISSIONS INTENSITY SINCE 20191 63% REDUCTION IN METHANE INTENSITY SINCE 2019 FIRST PERMIAN OPERATOR TO ACHIEVE THE TRUSTWELLTM CERTIFICATION FOR RESPONSIBLE OPERATIONS FOCUSED SHORT-TERM INCENTIVE PROGRAM SO THAT ENVIRONMENTAL GOALS MAKE UP 20% AND IMPLEMENTED A LONG-TERM INCENTIVE PROGRAM METRIC TIED TO ACHIEVING 2025 EMISSIONS REDUCTION GOALS INCREASED ACTIVE MANAGEMENT AND HIGH GRADING OF OUR VENDORS BASED ON SAFETY METRICS CONDUCTED FIRST SUPPLIER ESG SURVEY TO BETTER UNDERSTAND THE DIVERSITY OF OUR SUPPLY BASE AND THE ESG POLICIES THEY HAVE IN PLACE INCREASED BOARD GENDER AND ETHNIC DIVERSITY TO 60%, A 270% INCREASE SINCE 2019 CONDUCTED COMPANY-WIDE UNCONSCIOUS BIAS TRAINING 43% OF 2021 NEW HIRES WERE DIVERSE
3.4x 2.4x 2.3x 2.3x 2.2x 2.2x 2.1x 2.0x 2.0x 2.0x 1.9x 1.8x Average 1.5x 1.5x 1.4x 1.3x 1.3x 1.3x 1.3x 1.1x 1.1x 1.1x 1.0x LPI Generating Free Cash Flow1 Reducing Debt and Leverage Returning Capital to Shareholders 1See Appendix for definitions of non-GAAP financial measures 2Peer Group (PXD, CTRA, DVN, EOG, HES, CPE, SM, MRO, RRC, CLR, FANG, MTDR, AR, CNX, EQT, PDCE, APA, CHK, MUR, SWN, OVV); 3Source Capital One Research as of 10/26/2022 Compelling Investment Opportunity 11 Enterprise Value / PDP – Peer Comparison2,3 P e e r G ro u p 0.0x 2.0x 4.0x 6.0x 8.0x 0% 10% 20% 30% 2023E EV / EBITDAX vs. FCF Yield – Peer Comparison2,3 LPI Average
Appendix
4Q-22 GUIDANCE Guidance Commodity Prices Used for 4Q-22 Oct-22 Nov-22 Dec-22 4Q-22 Avg. Crude Oil: - - - - WTI NYMEX ($/BBO) $87.03 $86.21 $84.97 $86.07 Brent ICE ($/BBO) $93.50 $92.73 $90.88 $92.37 Natural Gas: - - - - Henry Hub ($/MMBTU) $6.87 $5.19 $6.36 $6.15 Waha ($/MMBTU) $3.28 $3.08 $4.83 $3.74 Natural Gas Liquids: - - - - C2 ($/BBL) $16.99 $17.01 $16.91 $16.97 C3 ($/BBL) $35.62 $36.86 $36.75 $36.40 IC4 ($/BBL) $44.82 $44.47 $43.47 $44.25 NC4 ($/BBL) $41.31 $42.21 $42.26 $41.92 C5+ ($/BBL) $68.35 $68.04 $68.09 $68.16 Composite ($/BBL)1 $32.30 $32.77 $32.67 $32.58 4Q-22 Production: - Total Production (MBOE/D) 72.5 – 75.5 Crude Oil Production (MBO/d) 32.0 – 34.0 Incurred Capital Expenditures ($MM): $135 - $145 Average Sales Price Realizations (excluding derivatives): - Crude Oil (% of WTI) 103% Natural Gas Liquids (% of WTI) 25% Natural Gas (% of Henry Hub) 47% Net Settlements Received (Paid) for Matured Commodity Derivatives ($MM): - Crude Oil ($MM) ($68) Natural Gas Liquids ($MM) ($3) Natural Gas ($MM) ($5) Operating Costs & Expenses ($/BOE): - Lease Operating Expenses $6.50 Production & Ad Valorem Taxes (% of Oil, NGL & Natural Gas Revenues) 7.3% Transportation and Marketing Expenses $1.80 General and Administrative Expenses (excluding LTIP) $2.15 General and Administrative Expenses (LTIP Cash) $0.40 General and Administrative Expenses (LTIP Non-Cash) $0.45 Depletion, Depreciation and Amortization $11.00 Note: Supports average sales price realization and derivatives guidance 13 1Current NGL composition C2 (42%), C3 (33%), IC4 (3%), NC4 (11%) and C5+ (11%) Currently Above High-End of Guidance Range
(Volume in MBO; Price in $/BBO) Q4-22 Q1-23 Q2-23 Q3-23 Q4-23 FY-23 Brent Swaps 1,040 - - - - - WTD Price $48.34 - - - - - Brent Collars 391 - - - - - WTD Floor Price $56.65 - - - - - WTD Ceiling Price $65.44 - - - - - WTI Swaps 92 - - - - - WTD Price $64.40 - - - - - WTI Collars 1,408 1,890 1,911 644 644 5,089 WTD Floor Price $72.65 $68.10 $68.10 $70.00 $70.00 $68.58 WTD Ceiling Price $86.54 $83.78 $83.78 $88.12 $88.12 $84.88 Total Swaps/Collars 2,930 1,890 1,911 644 644 5,089 WTD Floor Price $61.63 $68.10 $68.10 $70.00 $70.00 $68.58 (Volume in MBBL; Price in $/BBL) Q4-22 Q1-23 Q2-23 Q3-23 Q4-23 FY-23 Ethane Swaps 386 - - - - - WTD Price $11.42 - - - - - Propane Swaps 294 - - - - - WTD Price $35.91 - - - - - Butane Swaps 92 - - - - - WTD Price $41.58 - - - - - Isobutane Swaps 28 - - - - - WTD Price $42.00 - - - - - Pentane Swaps 92 - - - - - WTD Price $60.65 - - - - - (Volume in MMBTU; Price in $/MMBTU) Q4-22 Q1-23 Q2-23 Q3-23 Q4-23 FY-23 Henry Hub Swaps 920,000 - - - - - WTD Price $2.73 - - - - - Henry Hub Collars 7,360,000 6,300,000 6,370,000 6,440,000 6,440,000 25,550,000 WTD Floor Price $3.09 $4.14 $4.14 $4.14 $4.14 $4.14 WTD Ceiling Price $3.84 $8.43 $8.43 $8.43 $8.43 $8.43 Total Henry Hub Swaps/Collars 8,280,000 6,300,000 6,370,000 6,440,000 6,440,000 25,550,000 WTD Floor Price $3.05 $4.14 $4.14 $4.14 $4.14 $4.14 Waha Basis Swaps 7,314,000 6,300,000 6,370,000 6,440,000 6,440,000 25,550,000 WTD Price ($0.36) ($1.65) ($1.65) ($1.65) ($1.65) ($1.65) 1Hedges executed as of December 2, 2022 Active Hedge Program to Protect Free Cash Flow 14
Supplemental Non-GAAP Financial Measures Consolidated EBITDAX (Credit Agreement Calculation 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 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 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 Consolidated 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: 15 Three months ended, (in thousands, unaudited) 9/30/2022 6/30/2022 3/31/2022 12/31/2021 Net Income (loss) $337,523 $262,546 ($86,781) $216,276 Plus: Share-settled equity-based compensation, net 1,638 2,604 2,053 2,066 Depletion, depreciation and amortization 74,928 78,135 73,492 74,592 Organizational restructuring expenses 10,420 — — — (Gain) loss on disposal of assets, net (4,282) (38) 260 8,903 Mark-to-market on derivatives: (Gain) loss on derivatives, net (100,748) 65,927 325,816 (15,372) Settlements paid for matured derivatives, net (124,289) (174,009) (125,370) (129,361) Settlements received for contingent consideration — 1,555 — — Accretion expense 954 973 1,019 1,026 Interest expense 30,967 32,807 32,477 31,163 (Gain) loss on extinguishment of debt, net (553) 798 — — Income tax (benefit) expense (3,768) 7,092 (877) 3,052 Consolidated EBITDAX (non-GAAP) $222,790 $278,390 $222,089 $192,345
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. 16 (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 September 30, 2022 was $1.14 billion. Net Debt to Consolidated EBITDAX (Unaudited) 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. 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. 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. 17