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): September 8, 2021
(Exact name of registrant as specified in charter)
| (State or other jurisdiction of incorporation or organization) | (Commission File Number) | (I.R.S. Employer Identification No.) | ||||||
| (Address of principal executive offices) | (Zip code) | |||||||
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:
| Title of each class | Trading Symbol | Name of each exchange on which registered | ||||||
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) | |||||||||||
| Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) | |||||||||||
| Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) | |||||||||||
| Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) | |||||||||||
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 September 8, 2021, Laredo Petroleum, Inc. (the "Company") posted to its website an investor presentation (the "Presentation"). The Presentation is attached hereto as Exhibit 99.1 and incorporated into this Item 7.01 by reference. The Presentation is available on the Company's website, www.laredopetro.com.
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 Securities 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, 2020, its Current Report on Form 8-K, filed on May 11, 2021, and the Company's other filings with the U.S. 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 exhibits 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: September 8, 2021 | By: | /s/ Bryan J. Lemmerman | ||||||
| Bryan J. Lemmerman | ||||||||
| Senior Vice President and Chief Financial Officer | ||||||||
September 2021 Investor Presentation Exhibit 99.1
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 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, 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 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, 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, 2020, Current Report on Form 8-K, filed with the Securities and Exchange Commission ("SEC") on May 11, 2021, and those set forth from time to time in other filings with the 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 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 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 Laredo Petroleum: Pure-Play Permian Energy Producer Laredo Petroleum (NYSE: LPI) Market Capitalization1 $956 Million Enterprise Value1 $2.35 Billion Net Acres ~148,000 2021E Production2 ~78.5 MBOE/d 2021E Oil Production2 ~31.0 MBO/d Principles Laredo Leasehold Expand High-Margin Inventory Opportunistically acquire oil-weighted inventory High-grade development to maximize capital efficiency and increase oil cut Manage Risk Target Free Cash Flow3 generation and debt reduction Manage balance sheet and liquidity to facilitate optimal transaction financing Maintain a consistent commodity hedging program Continuously Improve Focus on efficiencies and low-cost operations Reduce GHG emissions intensity and flaring 1As of market close 9/3/2021; 2Utilizes mid-point of FY-21 guidance; 3See Appendix for definitions of non-GAAP financial measures
Continuously Improve Reduced percentage of produced natural gas flared/vented to 0.25% in 1H-21 from 0.71% for FY-20 Reduced drilling costs by 14% in 1H-21 versus FY-20 average Company-owned sand mine protects against sand cost inflation, saving an estimated $200,000 per well Commitment to reduce GHG emissions by 20% and eliminate routine flaring by 2025 Manage Risk No term-debt maturities until 2025 Extended credit facility maturity to 2025 Executed $75 million “at-the-market” equity program during 1H-21 Active hedge program in 2022 to protect forecasted Free Cash Flow1 Expect to reduce total leverage ratio to ~1.5x by YE-22 Rapidly Executing Transformational Strategy 41See Appendix for reconciliations and definitions of non-GAAP measures Expand High-Margin Inventory Added ~37,500 net acres of oil-weighted leasehold in five separate transactions Divested ~94 million BOE of legacy low- margin, gas-weighted reserves Development focused on recently acquired oil-weighted inventory in Howard and W. Glasscock counties Oil cut expected to rise from 31% in 1Q-21 to ~50% by YE-22
Laredo Leasehold Central Howard W. Glasscock North Howard Oily, High-Margin Inventory Built Through Acquisition Strategy 5 1Gross operated locations as of January 2021 (adjusted for 2020 completions), pro forma for acquisition closed 7/1/2021; 2Production data normalized to 10,000’ lateral length, downtime days excluded Map and acreage as of 7-8-21 W. Glasscock County Howard County Total Net acres ~4,350 ~33,150 ~37,500 Target formations LS/WC-A/WC-B LS/WC-A * Locations (gross)1 ~40 ~225 ~265 Drill Package Location
6 Development Focused on Acquired Leasehold Laredo Leasehold Central Howard W. Glasscock North Howard 2 12022 oil production based on expected development plan of 2 rigs and 1 frac crew; 2Wells completed by Sabalo prior to closing of transaction on 7-1-21; 2Five wells were spud by Sabalo prior to closing of transactions on 7-1-21 3 1 FY-21E Guidance FY-22E Preliminary1 Spuds 64 60 Completions 67 60 Working Interest 100% 96% Lateral Length 10,000' 11,500' Production, MBOE/d 77.0 - 80.0 75.0 - 78.0 Oil Production, MBO/d 30.5 - 31.5 36.0 - 38.0
$788 $764 $675 $610 $525 $0 $200 $400 $600 $800 FY-17 FY-18 FY-19 FY-20 1H-21 D C & E C o s t ($ /f t) Consistently Reducing DC&E Costs Maintaining Operational & Cost Advantages 7 - 300 600 900 1,200 1,500 1,800 2,100 1Q-17 F e e t p e r D a y Drilling & Completions Efficiencies Drilled Feet/Day/Rig Fractured Feet/Day/Crew FY-17 FY-18 FY-19 FY-20 1H-21
8 Laredo-Owned Sand Mine Saves on Completions Costs LPI Leasehold Mining Area Operated on Laredo-owned surface acreage 5+ years supply of sand Protects against sand cost inflation Reduces emissions ~$200,0001 savings per well versus market price Utilized in all 2Q-21 completions, 98% of all sand used Mine operated by a third party No additional capital investment beyond surface acreage acquisition Elimination of 300,000 miles per month of truck traffic and utilization of wet sand reduces emissions 1For Howard County completions
Operations Focused on Reducing Emissions 12019 calendar year as baseline; 2As a percentage of natural gas production 20% reduction in GHG intensity1 <0.20% methane emissions1,2 Zero routine flaring Emissions Reduction Targets for 2025 For the second consecutive year, flaring/venting reduction targets are part of executive compensation metrics 9
10 Corporate and Community Responsibility >$610,000 Total amount donated since 2019 to improve our local communities Giving Diversity1 Governance Laredo intends to disclose EEO-1 data by YE-21 Board refresh in last 2 years Independent Directors Female & Minority Directors Separated roles of Chairman and CEO October 2019 67% 89% 56% 27% Women in workforce Minorities in workforce Women and/or minorities in professional-or- higher roles 25% 61% Safety 0.86 0.74 2019 2020 TRIR2 Laredo had zero at-fault vehicle incidents in 2020 1Data as of 12-31-20; 2Combined employee and contractor Total Recordable Incident Rate
$578 $70 $655 $361 $400 $0 $200 $400 $600 $800 $1,000 $1,200 $1,400 2021 2022 2023 2024 2025 2026 2027 2028 2029 D e b t ($ M M ) Actively Managing our Balance Sheet & Liquidity 11 9.500% Senior Notes 2025 1See Appendix for reconciliations and definitions of non-GAAP measures; 2Balance as of 8-4-21; 3As of 7-12-21 No term-debt maturities until 2025 Executed “At-the-Market” equity program YTD 2021 resulting in ~$73 million of net proceeds Extended credit facility maturity until 2025 Active hedge program to protect Free Cash Flow1 Program expected to generate sustainable Free Cash Flow1 used to reduce debt and drive leverage down to 1.5x by YE-22 10.125% Senior Notes 2028 Drawn Credit Facility Undrawn Credit Facility Current Maturity Profile $673 MM Liquidity2 $62 MM Cash Balance2 7.750% Senior Notes 2029 Proceeds from issuance of 2029 notes used to pay down credit facility, significantly increasing liquidity Moody’s upgrades Laredo’s senior unsecured notes to B3 from Caa13
Active Hedge Program to Protect Free Cash Flow 12 1Hedge percentage calculated off mid-point guidance Note: NGL barrel composition includes 42% Ethane, 33% Propane, 11% Butane, 3% Isobutane and 11% Pentane
13 Guidance Production: 3Q-21 4Q-21 FY-21 Total production (MBOE/d) 74.5 - 77.5 77.5 - 80.5 77.0 - 80.0 Oil production (MBO/d) 33.5 - 35.5 37.5 - 39.5 30.5 - 31.5 Incurred capital expenditures1 ($ MM) $150 $105 $420 Average sales price realizations: (excluding derivatives) 3Q-21 Oil (% of WTI) 99% NGL (% of WTI) 35% Natural gas (% of Henry Hub) 75% Net settlements received (paid) for matured commodity derivatives ($ MM): 3Q-21 Oil ($48) NGL ($29) Natural Gas ($17) Other ($ MM): 3Q-21 Net income / (expense) of purchased oil ($6.8) Operating costs & expenses ($/BOE): 3Q-21 Lease operating expenses $3.90 Production and ad valorem taxes (% of oil, NGL and natural gas revenues) 6.50% Transportation and marketing expenses $1.60 General and administrative expenses (excluding LTIP) $1.65 General and administrative expenses (LTIP cash) ($0.20) General and administrative expenses (LTIP non-cash) $0.25 Depletion, depreciation and amortization $8.00 1Excludes non-budgeted acquisitions and leasehold expenses
L A R E D O P E T R O L E U M APPENDIX
15 Recent Acquisition/Divestiture Drives Significantly Higher Oil Cut Acquisition Overview_____________________________________________________________ Establishes core position in Howard County of >33,000 net acres Contiguous acreage position directly adjacent to existing position enables efficient operations Majority of midstream infrastructure in place and all agreements are acreage dedications with no MVC’s Extends development runway of high-margin, oil-weighted locations at conservative spacing assumptions of 12 wells per DSU (LS/WC-A) Purchase price of $715mm funded by: $405mm “Legacy” PDP sale | $201mm RBL draw1 | ~2.5mm common shares to sellers Divestiture Overview________________________________________________________________ Sale of 37.5% of Laredo’s gross working interest in operated PDP reserves to an affiliate of Sixth Street Partners LLC Initial proceeds of $405 million plus potential cash-flow based earn-out payments over six years Transaction solely within Laredo’s “Legacy” acreage footprint, wellbore only, no undeveloped locations Sabalo Laredo Laredo “Legacy” Acquisition Divestiture Net Acres ~21,000 * Gross Op Locations / Avg. WI ~120 / 91% WI * Gross Non-Op Locations / Avg. WI ~150 / 12% WI * Average Lateral Length 10,000’ * Current Net Production (three stream) ~13,600 BOE/d (89% oil) ~25,000 BOE/d (23% oil) PDP Reserves (three stream) ~30 million BOE (73% oil) ~94 million BOE (18% oil) 1Net of customary closing cost adjustments
Transactions Improve Company Fundamentals 16 1See Appendix for definitions of non-GAAP financial measures; 2Net Debt/TTM Consolidated EBITDAX Note: All projections assume current commodity prices Free Cash Flow1 ($mm) Leverage Net Debt to EBITDAX1,2 Gross Operated Locations Production Mix Expected cumulative Free Cash Flow1 of >$700mm by end of FY-25 Anticipate leverage1,2 approaching 1.0x by end of FY-25 Expected ~80% increase in oil-weighted, high-margin inventory Oil cut expected to rise to ~50% by end of FY-22 Expected to be accretive to long-term Free Cash Flow1 and Adjusted EBITDA1
17 Howard County Driving Reserves Value 1Based only on wells categorized as Proved Developed as of July 1, 2021 at the following SEC benchmark pricing: Oil $46.26/bbl, Natural Gas $2.07/mcf, Natural Gas Liquids $23.68/bbl; 2Based only on wells categorized as Proved Developed as of July 1, 2021 and normalized to $3.00 Henry Hub gas price 3See Appendix for definitions of non-GAAP measures 209,086 MBOE $1,564 MM PV-103 Howard County proved developed reserves are 69% oil, significantly increasing Laredo’s exposure to higher oil prices
Commodity Prices Used for 3Q-21 Average Sales Price Realization and Derivatives Guidance 18 Natural Gas: Natural Gas Liquids: Oil: Note: Pricing assumptions as of 7-30-21 WTI NYMEX Brent ICE ($/Bbl) ($/Bbl) Jul-21 $72.43 $74.25 Aug-21 $73.72 $75.37 Sep-21 $72.96 $74.55 3Q-21 Average $73.04 $74.73 C2 C3 IC4 NC4 C5+ Composite ($/Bbl) ($/Bbl) ($/Bbl) ($/Bbl) ($/Bbl) ($/Bbl) Jul-21 $13.15 $45.74 $53.11 $52.68 $67.33 $35.41 Aug-21 $13.55 $47.36 $55.55 $55.39 $69.83 $36.76 Sep-21 $13.65 $47.62 $55.70 $55.49 $69.93 $36.91 3Q-21 Average $13.45 $46.90 $54.79 $54.52 $69.03 $36.36 HH Waha ($/MMBtu) ($/MMBtu) Jul-21 $3.62 $3.36 Aug-21 $4.04 $3.87 Sep-21 $3.91 $3.68 3Q-21 Average $3.86 $3.64
Supplemental Non-GAAP Financial Measures Adjusted EBITDA Adjusted EBITDA is a non-GAAP financial measure that we define as net income or loss (GAAP) 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): 19 Three months ended, (in thousands, unaudited) 9/30/2020 12/31/2020 3/31/2021 6/30/2021 Net loss ($237,432) ($165,932) ($75,439) ($132,661) Plus: Share-settled equity-based compensation, net 2,041 2,106 2,068 1,730 Depletion, depreciation and amortization 47,015 42,210 38,109 39,976 Impairment expense 196,088 109,804 — 1,613 Organizational restructuring expenses — — — 9,800 Transaction expenses — — — 1,741 Mark-to-market on derivatives: (Gain) loss on derivatives, net 45,250 81,935 154,365 216,942 Settlements received (paid) for matured derivatives, net 51,840 41,786 (41,174) (57,607) Settlements received for early-terminated commodity derivatives, net 6,340 — — — Net premiums paid for commodity derivatives that matured during the period(1) — — (11,005) (10,183) Accretion expense 1,102 1,105 1,143 1,158 (Gain) loss on disposal of assets, net 607 (94) 72 (66) Interest expense 26,828 26,139 25,946 25,870 Gain on extinguishment of debt, net — (22,309) — — Income tax (benefit) expense (2,398) 3,208 (762) (1,322) Adjusted EBITDA $137,281 $119,958 $93,323 $96,991 (1) Reflects net premiums paid previously or upon settlement that are attributable to derivatives settled in the respective periods presented
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 loss (GAAP) to Consolidated EBITDAX (Credit Agreement Calculation; non-GAAP): 20 Three months ended, (in thousands, unaudited) 9/30/2020 12/31/2020 3/31/2021 6/30/2021 Net loss ($237,432) ($165,932) ($75,439) ($132,661) Organizational restructuring expenses — — — 9,800 Gain on extinguishment of debt, net — (22,309) — — (Gain) loss on disposal of assets, net 607 (94) 72 (66) Consolidated Net Loss (236,825) (188,335) (75,367) (122,927) Mark-to-market on derivatives: Loss on derivatives, net 45,250 81,935 154,365 216,942 Settlements received (paid) for matured derivatives, net 51,840 41,786 (41,174) (57,607) Settlements received for early-terminated commodity derivatives, net 6,340 — — — Mark-to-market loss on derivatives, net 103,430 123,721 113,191 159,335 Premiums received for commodity derivatives — — 9,041 — Non-Cash Charges/Income: Deferred income tax (benefit) expense (2,398) 3,208 (762) (1,322) Depletion, depreciation and amortization 47,015 42,210 38,109 39,976 Share-settled equity-based compensation, net 2,041 2,106 2,068 1,730 Accretion expense 1,102 1,105 1,143 1,158 Impairment expense 196,088 109,804 — 1,613 Interest Expense 26,828 26,139 25,946 25,870 Consolidated EBITDAX after EBITDAX Adjustments (limited to 15%) (non-GAAP) $137,281 $119,958 $113,369 $105,433
Net Debt Net Debt, a non-GAAP financial measure, is calculated as the face value of long-term debt 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 6-30-21 was $1.125 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 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. 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 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. 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 is a non-GAAP financial measure, that we define 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 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. We are 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. 21 Supplemental Non-GAAP Financial Measures
22 Supplemental Non-GAAP Financial Measures PV-10 PV-10, a non-GAAP financial measure, 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. We are unable to provide a reconciliation of the forward-looking PV-10 projection contained in this presentation to the standardized measure of discounted future net cash flows, the most directly comparable GAAP financial measure, because we cannot reliably predict certain of the necessary components of the standardized measure of discounted future net cash flows, such as reserve additions, extensions, price and performance revisions, and taxes outside of the normal year-end reserve evaluation process without unreasonable efforts. Such unavailable reconciling information may be significant.