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LPI Laredo Petroleum

Filed: 7 Dec 20, 4:47pm
Capital One Securities 15th Annual Energy Conference December 8, 2020 Exhibit 99.1


 

Forward-Looking / Cautionary Statements 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. 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, 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 and actions by OPEC+, long-term performance of wells, drilling and operating risks, the increase in service and supply costs, tariffs on steel, pipeline transportation and storage constraints in the Permian Basin, the possibility of production curtailment, hedging activities, 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 our 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, 2019, Amendment No. 1 to its Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, its Quarterly Report on Form 10-Q for the quarter ended June 30, 2020, its Quarterly Report on Form 10-Q for the quarter ended September 30, 2020 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 or “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 Adjusted EBITDA, Cash Flow 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 a reconciliation of such non-GAAP financial measures to the nearest comparable measure in accordance with GAAP, 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


 

3 Laredo Petroleum: Executing Strategy to Increase Stakeholder Value 1 See Appendix for reconciliations and definitions of non-GAAP measures; 2As of 10-16-20 Acquired beginning Dec-19 Howard County - 11,299 net acres2 W. Glasscock County - 4,352 net acres2 Expand High-Margin Inventory Manage Risk  No term-debt maturities until 2025  Active hedging strategy supports cash flows  Focus on ESG best practices Optimize Assets  Peer-leading cash cost metrics  Well cost among lowest in Midland Basin  Conservative development spacing  Added 16,000 net acres in Howard / W. Glasscock counties in last 12 months  Development transitioned to recent acquisitions  New acreage driving a capital efficiency inflection point 133,710 total net acres2Improve Oil Cut Reduce leverage Expand Margins Target Free Cash Flow1 Objectives Principles


 

$255 $578 $361 $470 $0 $200 $400 $600 $800 FY-20 FY-21 FY-22 FY-23 FY-24 FY-25 FY-26 FY-27 FY-28 D e b t ($ M M ) Actively Managing our Balance Sheet and Debt Ratios 1See Appendix for reconciliations and definitions of non-GAAP measures 2Includes TTM Adjusted EBITDA/Consolidated EBITDAX as of 9-30-20 and net debt as of 12-4-20 3Amount shown as of 12-4-20 2.2x Net Debt to Adj. EBITDA1,2 2.5x Net Debt to Consolidated EBITDAX1,2 $31 MM Cash Balance3 4 Credit Agreement drawn3Senior unsecured notes Credit Agreement undrawn3 Repurchased $61.0 MM face value of unsecured notes for $38.1 MM  62.5% of par, average purchase price  $22.9 MM net debt reduction related to repurchase of notes  $4.5 MM annualized interest savings


 

$250 $300 $350 $400 $35 $40 $45 $50 $55 WTI ($/Bbl) FY-21 Cash Flow3,4 ($ MM) Active Derivatives Strategy Manages Price Risk and Supports Cash Flow 5 Oil Natural Gas NGL 1Does not include premiums paid for commodity derivatives that mature in 2021; 2Open positions as of 9-30-20; hedges executed through 12-4-20; 3 Natural gas price held flat at $3/Mcf; 4See Appendix for reconciliations and definitions of non-GAAP measures; 5Utilizes midpoint of 2021 anticipated capital expenditure range of $325 - $350 MM 8,085 7,087 5,245 0 2,000 4,000 6,000 8,000 10,000 FY-21 Hedged Product Volumes2 (MBOE) Cash Flow, Including Hedges Capital Midpoint5 Reduce expenditures to operate within cash flow Excess cash flow to reduce net debt $47.2 $86.9 $58.2 $0 $20 $40 $60 $80 $100 1Q-20 2Q-20 3Q-20 Net Cash Received from Derivatives Settlements1 in 2020 ($ MM)


 

$788 $764 $675 $640 $540 $0 $200 $400 $600 $800 FY-17 FY-18 FY-19 1H-20 Current Estimated Cost D & C C o s t ($ /f t) 0 400 800 1,200 1,600 1Q-17 2Q-17 3Q-17 4Q-17 1Q-18 2Q-18 3Q-18 4Q-18 1Q-19 2Q-19 3Q-19 4Q-19 1Q-20 2Q-20 3Q-20 F e e t p e r D a y Drilled Feet/Day/Rig Fractured Feet/Day/Crew Maintaining Operational & Cost Advantages in Move to Howard County 6 Consistently Reducing DC&E Costs Drilling & Completions Efficiencies 1Based on internal estimates as of Dec-20 Efficiency gains maintained in move to Howard County 1


 

7 Howard County Sand Mine Drives Additional D&C Cost Reductions LPI Leasehold Mining Area Operated on Laredo-owned surface acreage 5+ years supply of sand Protects against sand cost inflation Reduces truck traffic by 300,000 miles per month Estimated savings of $90,0001 per well  Integrated into operations as of mid-November  Mine operated by a third party  No additional capital investment beyond surface acreage acquisition 1For Howard County completions


 

$3.61 $0 $2 $4 $6 $8 $ /B O E LOE Cash G&A Expense $10.66 $7.60 $6.38 $6.07 $4.65 $3.71 $0 $2 $4 $6 $8 $10 $12 FY-15 FY-16 FY-17 FY-18 FY-19 YTD-20 $ /B O E Demonstrated History of Expense Reduction Cash G&A Expense LOE Cost-Control Focus Improves Margins 8 1Excludes long-term incentive plan (“LTIP”) cash & non-cash compensation expenses Note: Peer results are based on 3Q-20 public filings and include: CDEV, CPE, ESTE, MTDR, PE, QEP, SM and WPX Peer Avg.: $6.05/BOE Peer-Leading Controllable Cash Costs 1 1 Peers 3Q-20 LPI


 

Acquired beginning Dec-19 $0 $5 $10 $15 $20 $25 0 4,000 8,000 12,000 16,000 20,000 Dec-19 Dec-19 Feb-20 Apr-20 Oct-20 Total N e t A c q u is it io n C o s t ($ M / A c ) A c q u ir e d N e t A c re s Closing Date Acquisition Cost per Undeveloped Acre Acquisitions Add Oily, High-Margin Inventory LPI Leasehold (133,710 net acres) 9 W. Glasscock County Total Net Acres 4,352 Targets LS/UWC/MWC Locations 45 Howard County Total Net Acres 11,299 Targets LS/UWC/MWC Locations 120 - 155  Acquisitions expected to add 3+ years of high-margin inventory and >1,600 BOE/d of production  All development activity has transitioned to Howard and W. Glasscock counties  First development package in Howard County expected to be online by end of 4Q-20 1Subject to a previously disclosed potential contingency payment; 2Net purchase price includes an adjustment for acquired production Map, acreage and locations as of 10-16-20 Acquired Net Acres Net Acquisition Cost ($M/Ac) 1 22 1


 

10 Howard County Development Utilizing Conservative Spacing Lower Spraberry Lower Spraberry 1,320’ Spacing 16 Wells per Section Development spacing optimizes returns and total value based on current commodity prices and well cost UWC/MWC 880’ Spacing Upper Wolfcamp Middle Wolfcamp UWC/MWC 1,320’ Spacing LPI Leasehold 16 Wells per Section 12 Wells per Section Lower Spraberry 1,320’ Spacing 12 Wells per Section Packages 3 and 4Packages 1 and 2 WC-A WC-B 150’


 

$482 26.6 27.0 28.4 27.1 29.0 15 20 25 30 35 $0 $100 $200 $300 $400 $500 $600 FY-19A FY-20E FY-21E O il P ro d u c ti o n ( M B O /d ) C a p it a l ($ M M ) 2021 Plan 11 Acquired Acreage Driving Future Capital Efficiency 1Capital expectations exclude non-budgeted acquisitions 2Utilizes current productivity and spacing assumptions; well cost assumptions of $5.5 MM 2021 plan focused on Howard County development Oil Production (MBO/d)Capital1 ($ MM) $0 $10 $20 $30 $40 $50 $60 0 20 40 60 80 100 120 140 160 180 Established Acreage UWC/MWC Western Glasscock County Howard County W e ll C o s t/ F ir s t- Y e a r O il P ro d u c ti o n ($ /B b l) F ir s t- Y e a r O il P ro d u c ti o n ( M B O ) First-Year Cumulative Oil Production vs Well Cost2 $340- $350 $325- $350


 

0% 10% 20% 30% 40% Permian Flared / Vented Gas vs. Gross Gas Production1 0.0% 1.0% 2.0% 3.0% 4.0% 5.0% 0 200 400 600 800 1,000 1,200 1,400 1Q-18 2Q-18 3Q-18 4Q-18 1Q-19 2Q-19 3Q-19 4Q-19 1Q-20 2Q-20 3Q-20 T o ta l F la re & V e n t (% o f T o ta l p ro d u c ti o n ) F la re d & V e n te d G a s ( M M c f) LPI Flared & Vented Natural Gas Flared & Vented Natural Gas Flared & Vented Natural Gas as % of Gas Production Protecting the Environment 1Source: Rystad Energy as of 10-28-20, with data beginning as of January 2018; Peers include: APA, AXAS, BATL, BP, CDEV, COP, CPE, CVX, CXO, DVN, EOG, EPEGQ, FANG, LLEX, MRO, MTDR, OAS, OVV, OXY, PDCE, PE, PXD, QEP, REI, ROSE, RYDAF, SM, WPX, XEC and XOM 12 0.14% LPI flared gas in 3Q-20 1.5% LPI flared gas is nearly half of the peer average over the past two years Peer Wtd.-Avg.: 2.93% Basin-wide gas takeaway constraints Peer LPI


 

13 Committed to ESG >$230,000 Pledged & donated by Laredo employees since 2019 >$185,000 Matched by Laredo through the Company’s Matching Gifts Program >$150,000 Donated to non-profits through community matching initiatives >$570,000 Total amount donated since 2019 to improve our local communities SocialEnvironment Governance Inaugural sustainability report to be released 1Q-21 Board refresh in last 2 years Female Directors Minority Directors Separated roles of Chairman and CEO October 2019 55% 36% 9% 54% Reduction in flared/vented gas as a percentage of total produced gas vs 2019 15% STIP compensation1 tied to environmental metrics 0.90% Flared/vented gas as a percentage of total produced gas YTD-20 1Of objective criteria


 

L A R E D O P E T R O L E U M APPENDIX 14


 

Oil, Natural Gas & Natural Gas Liquids Hedges 1Includes 97,000 MMBtu/d in Oct-20 - Nov-20 and 65,000 MMBtu/d Dec-20 Note: Open positions as of 9-30-20, hedges executed through 12-4-20 Natural gas liquids consist of Mt. Belvieu purity ethane and Mt. Belvieu non-TET propane, normal butane, isobutane, and natural gasoline 15 Hedge Product Summary 4Q-20 FY-21 FY-22 Oil total volume (Bbl) 2,107,720 8,084,750 3,759,500 Oil wtd-avg price ($/Bbl) - WTI $59.35 Oil wtd-avg price ($/Bbl) - Brent $63.07 $50.80 $47.05 Nat gas total volume (MMBtu) 11,897,000 42,522,500 3,650,000 Nat gas wtd-avg price ($/MMBtu) - HH $2.65 $2.59 $2.73 NGL total volume (Bbl) 644,000 5,245,050 Natural Gas Liquids Swaps 4Q-20 FY-21 FY-22 Ethane Volume (Bbl) 92,000 912,500 Wtd-avg price ($/Bbl) $13.60 $12.01 Propane Volume (Bbl) 312,800 2,423,235 Wtd-avg price ($/Bbl) $26.58 $22.90 Normal Butane Volume (Bbl) 110,400 807,745 Wtd-avg price ($/Bbl) $28.69 $25.87 Isobutane Volume (Bbl) 27,600 220,460 Wtd-avg price ($/Bbl) $29.99 $26.55 Natural Gasoline Volume (Bbl) 101,200 881,110 Wtd-avg price ($/Bbl) $45.15 $38.16 Natural Gas Swaps 4Q-20 FY-21 FY-22 HH Volume (MMBtu) 11,897,0001 42,522,500 3,650,000 Wtd-avg price ($/MMBtu) $2.65 $2.59 $2.73 Basis Swaps 4Q-20 FY-21 FY-22 Waha/HH Volume (MMBtu) 10,580,000 41,610,000 7,300,000 Wtd-avg price ($/MMBtu) ($0.82) ($0.55) ($0.53) Oil 4Q-20 FY-21 FY-22 WTI Swaps Volume (Bbl) 1,509,720 Wtd-avg price ($/Bbl) $59.35 Brent Swaps Volume (Bbl) 598,000 5,037,000 3,759,500 Wtd-avg price ($/Bbl) $63.07 $49.43 $47.05 Brent Puts Volume (Bbl) 2,463,750 Wtd-avg floor price ($/Bbl) $55.00 Brent Collars Volume (Bbl) 584,000 Wtd-avg floor price ($/Bbl) $45.00 Wtd-avg ceiling price ($/Bbl) $59.50 Oil Basis Swaps 4Q-20 FY-21 FY-22 Brent/WTI Volume (Bbl) 901,600 Wtd-avg price ($/Bbl) $5.09


 

Guidance Production: 4Q-20 FY-20 Total production (MBOE/d) 82.0 - 84.0 87.6 - 88.1 Oil production (MBO/d) 21.0 - 23.0 26.6 - 27.1 16 Average sales price realizations: (excluding derivatives) 4Q-20 Oil (% of WTI) 95% NGL (% of WTI) 26% Natural gas (% of Henry Hub) 49% Other ($ MM): 4Q-20 Net income / (expense) of purchased oil ($4.3) Net midstream income / (expense) $0.75 Operating costs & expenses ($/BOE): 4Q-20 Lease operating expenses $2.80 Production and ad valorem taxes (% of oil, NGL and natural gas revenues) 7.25% Transportation and marketing expenses $1.95 General and administrative expenses (excluding LTIP) $1.25 General and administrative expenses (LTIP cash & non-cash) $0.35 Depletion, depreciation and amortization $6.00


 

Commodity Prices Used for 4Q-20 Realization Guidance 17 Natural Gas: Natural Gas Liquids: Oil: Note: Pricing assumptions as of 11-2-20 WTI NYMEX Brent ICE ($/Bbl) ($/Bbl) Oct-20 $39.56 $41.55 Nov-20 $36.90 $38.99 Dec-20 $37.32 $39.50 4Q-20 Average $37.94 $40.03 C2 C3 IC4 NC4 C5+ Composite ($/Bbl) ($/Bbl) ($/Bbl) ($/Bbl) ($/Bbl) ($/Bbl) Oct-20 $9.03 $21.74 $26.89 $26.65 $36.50 $18.90 Nov-20 $9.46 $23.05 $28.78 $28.77 $34.02 $19.54 Dec-20 $9.49 $23.12 $28.58 $27.50 $34.06 $19.42 4Q-20 Average $9.33 $22.63 $28.07 $27.63 $34.87 $19.29 HH Waha ($/MMBtu) ($/MMBtu) Oct-20 $2.10 $1.29 Nov-20 $3.00 $1.60 Dec-20 $3.24 $2.96 4Q-20 Average $2.78 $1.95


 

18 Howard County Bolt-On Acquisition Announced October 2020 Acquisition Highlights  Acquired 2,758 net acres adjacent to existing Howard County acreage  Company’s position is now 11,299 net acres  Added 12 new 10,000-foot locations, with the potential for 25 additional locations as drilling units are formed  Increased working interest and lateral length of 12 existing locations, from 45% to 83% & 7,500’ to 10,000’, respectively  Includes production of 210 BOE/d (80% oil)  Low-cost financing with entire transaction funded by Senior Secured Credit Facility LPI Leasehold Oct-20 Acquisition Undeveloped acreage acquired at $2,200/acre1 1Net purchase price includes an adjustment for acquired production Map, acreage and locations as of 10-16-20


 

YE-19 Base Production Decline Expectations 19 86.5 60.8 49.8 42.4 37.1 33.2 0 20 40 60 80 100 Dec-19 Dec-20 Dec-21 Dec-22 Dec-23 Dec-24 M B O E /d Total Production Decline 27.5 15.4 11.7 9.6 8.2 7.2 0 5 10 15 20 25 30 Dec-19 Dec-20 Dec-21 Dec-22 Dec-23 Dec-24 M B O /d Oil Production Decline


 

20 Increased Activity Accelerates Development of Howard County DUCs 1Q-20A 2Q-20A 3Q-20A 4Q-20E FY-20E Drilling Rigs 4.0 2.4 1.0 1.0 2.1 Spuds 25 17 7 6 55 Completion Crews 1.7 0.3 0.3 1.0 0.8 Completions 28 5 0 15 48 Total Capital1 ($MM) $155 $78 $43 $64 - $74 $340 - $350 Avg. Working Interest 98% Avg. Lateral Length 9,000 1Excluding non-budgeted acquisitions


 

Supplemental Non-GAAP Financial Measures Adjusted EBITDA Adjusted EBITDA is a non-GAAP financial measure that we define as net income or loss plus adjustments for share-settled equity-based compensation, depletion, depreciation and amortization, impairment expense, mark-to-market on derivatives, premiums paid for commodity derivatives that matured during the period, accretion expense, gains or losses on disposal of assets, interest expense, income taxes and other non-recurring income and expenses. Adjusted EBITDA provides no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, working capital movement or tax position. Adjusted EBITDA 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, our management believes Adjusted EBITDA is useful to an investor in evaluating our operating performance 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 our operations from period to period by removing the effect of our capital structure from our operating structure; and is used by our management for various purposes, including as a measure of operating performance, in presentations to our board of directors and as a basis for strategic planning and forecasting. There are significant limitations to the use of Adjusted EBITDA as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss and the lack of comparability of results of operations to different companies due to the different methods of calculating Adjusted EBITDA reported by different companies. Our measurements of Adjusted EBITDA for financial reporting as compared to compliance under our debt agreements differ. The following table presents a reconciliation of net income (loss) (GAAP) to Adjusted EBITDA (non-GAAP): 21 1Reflects revised and restated figures in 1Q-20 10-Q/A Three months ended, (in thousands, unaudited) 12/31/19 3/31/201 6/30/20 9/30/20 Net income (loss) ($241,721) $74,646 ($545,455) ($237,432) Plus: Share-settled equity-based compensation, net 3,046 2,376 1,694 2,041 Depletion, depreciation and amortization 67,846 61,302 66,574 47,015 Impairment expense 222,999 186,699 406,448 196,088 Organizational restructuring expenses — — 4,200 — Mark-to-market on derivatives: (Gain) loss on derivatives, net 57,562 (297,836) 90,537 45,250 Settlements received for matured derivatives, net 14,394 47,723 86,872 51,840 Settlements received for early-terminated commodity derivatives, net — — — 6,340 Premiums paid for commodity derivatives that matured during the period (1,399) (477) — — Accretion expense 1,041 1,106 1,117 1,102 (Gain) loss on disposal of assets, net (67) 602 (152) 607 Interest expense 15,044 24,970 27,072 26,828 Loss on extinguisment of debt — 13,320 — — Write-off of debt issuance costs 935 — 1,103 — Income tax (benefit) expense (1,776) 2,417 (7,173) (2,398) Adjusted EBITDA $137,904 $116,848 $132,837 $137,281


 

Supplemental Non-GAAP Financial Measures Consolidated EBITDAX (Credit Agreement Calculation) “Consolidated EBITDAX” means, for any Person for any period, the Consolidated Net Income of such Person for such period, plus each of the following, to the extent deducted in determining Consolidated Net Income without duplication, determined for such Person and its Consolidated Subsidiaries on a consolidated basis for such period: any provision for (or less any benefit from) income or franchise Taxes; interest expense (as determined under GAAP as in effect as of December 31, 2016), depreciation, depletion and amortization expense; exploration expenses; and other non-cash charges to the extent not already included in the foregoing clauses (ii), (iii) or (iv), plus the aggregate Specified EBITDAX Adjustments during such period; provided that the aggregate Specified EBITDAX Adjustments shall not exceed fifteen percent (15%) of the Consolidated EBITDAX for such period prior to giving effect to any Specified EBITDAX Adjustments for such period, and minus all non-cash income to the extent included in determining Consolidated Net Income. For the purposes of calculating Consolidated EBITDAX for any Rolling Period in connection with any determination of the financial ratio contained in Section 10.1(b), if during such Rolling Period, Borrower or any Consolidated Restricted Subsidiary shall have made a Material Disposition or Material Acquisition, the Consolidated EBITDAX for such Rolling Period shall be calculated after giving pro forma effect thereto as if such Material Disposition or Material Acquisition, as applicable, occurred on the first day of such Rolling Period. For additional information, please see the Company's Fifth Amended and Restated Credit Agreement, as amended, dated May 2, 2017 as filed with Securities and Exchange Commission. The following table presents a reconciliation of net income (loss) (GAAP) to Consolidated EBITDAX (Credit Agreement Calculation; non-GAAP): 22 1Reflects revised and restated figures in 1Q-20 10-Q/A Three months ended, (in thousands, unaudited) 12/31/19 3/31/201 6/30/20 9/30/20 Net income (loss) ($241,721) $74,646 ($545,455) ($237,432) Organizational restructuring expenses — — 4,200 — Loss on extinguishment of debt — 13,320 — — (Gain) loss on disposal of assets, net (67) 602 (152) 607 Consolidated Net Income (Loss) (241,788) 88,568 (541,407) (236,825) Mark-to-market on derivatives: (Gain) loss on derivatives, net 57,562 (297,836) 90,537 45,250 Settlements received for matured derivatives, net 14,394 47,723 86,872 51,840 Settlements received for early-terminated commodity derivatives, net — — — 6,340 Mark-to-market (gain) loss on derivatives, net 71,956 (250,113) 177,409 103,430 Premiums paid for commodity derivatives (1,399) (477) (50,593) — Non-Cash Charges/Income: Deferred income tax expense (benefit) (1,776) 2,417 (7,173) (2,398) Depletion, depreciation and amortization 67,846 61,302 66,574 47,015 Share-settled equity-based compensation, net 3,046 2,376 1,694 2,041 Accretion expense 1,041 1,106 1,117 1,102 Impairment expense 222,999 186,699 406,448 196,088 Write-off of debt issuance costs 935 — 1,103 — Interest Expense 15,044 24,970 27,072 26,828 Consolidated EBITDAX after EBITDAX Adjustments $137,904 $116,848 $82,244 $137,281


 

Net Debt Net Debt, a non-GAAP financial measure, is calculated as long-term debt less cash. 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 12-4-20 was $1.163 B. Net debt to TTM Adjusted EBITDA Net Debt to TTM Adjusted EBITDA is calculated as net debt divided by trailing twelve-month Adjusted EBITDA. Net debt is calculated as the face value of debt, reduced by cash and cash equivalents. Net Debt to Adjusted EBITDA is used by our management for various purposes, including as a measure of operating performance, in presentations to our board of directors and as a basis for strategic planning and forecasting. See Appendix slides for a definition of Adjusted EBITDA and for a reconciliation of Net Income to Adjusted EBITDA. Net debt to TTM Consolidated EBITDAX (Credit Agreement Calculation) Net Debt to TTM Consolidated EBITDAX is calculated as net debt divided by trailing twelve-month Consolidated EBITDAX. Net debt is calculated as the face value of debt, reduced by cash and cash equivalents. Net Debt to Consolidated EBITDAX is used by the banks in our Senior Secured Credit Agreement as a measure of indebtedness and as a calculation to measure compliance with the Company’s leverage covenant. See Appendix slides for a definition of Consolidated EBITDAX and for a reconciliation of Net Income to Consolidated EBITDAX. Liquidity Calculated as the Company’s outstanding borrowings on its Senior Secured Credit Agreement, less outstanding letters of credit, plus cash and cash equivalents. Cash Flow Cash flow, a non-GAAP financial measure, represents cash flows from operating activities before changes in operating assets and liabilities, net. Free Cash Flow Free Cash Flow, a non-GAAP financial measure, represents net cash provided by operating activities before changes in operating assets and liabilities, net, less costs incurred, excluding non-budgeted acquisition costs. It 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. Management believes Free Cash Flow is useful to management and investors in evaluating operating trends in our 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. 23 Supplemental Non-GAAP Financial Measures