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 2, 2020
(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:
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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) | |||||||||||
| 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. o | |||||||||||
Item 7.01. Regulation FD Disclosure.
On September 2, 2020, Laredo Petroleum, Inc. (the "Company") posted to its website an Investor Presentation (the "Presentation"). 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, 2019 and the Company's other filing with the SEC 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 and exhibit be deemed incorporated by reference in to 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 2, 2020 | By: | /s/ Bryan J. Lemmerman | ||||||
| Bryan J. Lemmerman | ||||||||
| Senior Vice President and Chief Financial Officer | ||||||||
EXHIBIT 99.1 September 2020 Investor Presentation
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, 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 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,” and “type curve” 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, drilling results, 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, our 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. 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. 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”), including 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 Adjusted EBITDA, Cash Flow and Free Cash Flow 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 our derivative transactions. All amounts, dollars and percentages presented in this presentation are rounded and therefore approximate. 2
Successfully Operating in a Turbulent Macro Environment Current Costs vs YE-191 Well Costs LOE G&A $550 per foot $2.40/BOE $1.24/BOE 19% reduction 15% reduction 28% reduction Financial & Operational Highlights Successfully Reduced flared / Maintaining Increased FY-21 extended all vented gas to drilling oil hedges to term-debt only 1.1% of total efficiencies 80% of expected maturities until natural gas during transition oil production2 2025 and 2028 production to Howard County Reduced expected capital expenditures for FY-203 by 28% versus FY-19 1 Current data as of 2Q-20, YE data as of 4Q-19 2 Based on hedges executed through 9-1-20 and midpoint of current plan 3 3 Based on midpoint of guidance, excludes non-budgeted acquisitions
Strategy to Increase Stakeholder Value Foundation Manage Optimize Financial Risk Existing Assets Expand High- Consolidate to Margin Inventory Increase Scale Objectives Improve Reduce Expand Target Free oil cut leverage margins Cash Flow1 4 1See Appendix for reconciliations and definitions of non-GAAP measures
Acquisitions Added Oily, High-Margin Inventory Acquired beginning Nov-19 Howard County Total Est. Acreage Total Net Acres 8,594 Net Acres 118,047 Targets LS/UWC/MWC Targets UWC/MWC/Cline Locations 130 Locations 440 - 610 W. Glasscock Cty Total Established Acreage Net Acres 4,352 . 500 developed horizontal Targets LS/UWC/MWC locations and production of Locations 45 94,100 BOE/d (33% oil) High-margin (50+% oil), . Extensive Company-owned oil, higher-return inventory gas and water infrastructure reduces capital and operating Contiguous Midland Basin costs while minimizing acreage positioned to benefit environmental impacts from LPI’s peer-leading operational costs and efficiencies . Leasehold is 91% HBP, requiring minimal development capital to Target long-term, consistent Free maintain acreage position and Cash Flow1 generation and undeveloped locations leverage ratio reduction LPI Leasehold (130,993 net acres) Acquired high-return, oily locations move to front of development schedule 1See Appendix for reconciliations and definitions of non-GAAP measures 5 Map, acreage and locations as of 06-30-20
Howard County Oil Productivity Drives Returns 100% 80% (%) 60% 1 40% 8,594 net acres ROR 20% LPI Leasehold 0% $35 $40 $45 $50 WTI ($/Bbl) LPI Howard County Budget Howard County Budget Cumulative Oil Production Compared to Established Acreage 250 200 150 100 Cumulative OilCumulative 50 Production(MBO) 0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Months LPI Howard County Budget LPI Established Acreage Regional Cline Oil Type Curve LPI Established Acreage UWC/MWC Oil Type Curve Expect to complete first 15-well package in Howard County during 4Q-20 1Returns are based on $5.5 MM well costs; applicable natural gas strip pricing details can be found in the Appendix 6 Note: Map as of 06-30-20
Maintaining Operational & Cost Advantages in Move to Howard County Drilling & Completions Efficiencies 1,600 Drive Continued Well Cost Reductions 1,200 Inefficiencies due to 800 suspension of completions operations 400 Drilling efficiencies Feet per Day per Feet sustained with rig move to Howard County 0 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 Drilled Feet/Day/Rig Fractured Feet/Day/Crew Among the Lowest Midland Basin D&C Costs1 $1,000 Peer Avg.: $746/ft $750 $500 $550 $250 Average Cost/Ft Average $0 Peer Peer Peer Peer Peers Peer Peer Peer Peer LPILPI LPILPI CurrentCurrent2 1Source: RSEG 7-27-2020 2019 & 2020 quarterly weighted average lateral cost per foot. Peers include: CPE, CXO, FANG, OVV, PE, PXD, QEP, and SM 7 2Based on internal estimates as of 2Q-20
Cost-Control Focus Drives Expense Improvements $12 Demonstrated History of Expense Reduction ($/BOE) $10.66 $10 $8 $7.60 $6.38 $6.07 $6 $4.65 $/BOE $4.13 $4 $3.42 $2 $0 FY-15 FY-16 FY-17 FY-18 FY-19 1Q-20 2Q-20 Cash G&A Expense1 LOE $10 2Q-20 Peer-Leading Controllable Cash Costs ($/BOE) $8 Peer Avg.: $5.98/BOE $6 $/BOE $4 $3.42 $2 $0 2Q-20 Peer Peer Peer Peer Peers Peer Peer Peer Peer LPI LPI Cash G&A Expense1 LOE 1Excludes long-term cash & non-cash compensation expenses 8 Note: Peer results are based on most recent public filing and include: CDEV, CPE, ESTE, MTDR, PE, QEP, SM and WPX
Optimized Development Supports Consistent Oil Outperformance Optimized / Wider-Spaced Packages Deliver Oil Outperformance Exceeding Type Curve by 13%1,2 180 160 140 120 100 80 60 40 Cumulative Production(MBO) OilCumulative 20 W. Glasscock Cook Package production results are improving after upgrading flow lines and optimizing artificial lift operations 0 0 30 60 90 120 150 180 210 240 270 300 330 360 390 420 450 480 Producing Days Wider-Spaced Well Avg.2 LPI UWC/MWC Type Curve3 Wider-Spaced Package W. Glasscock Cook Package Avg. 1Wider-Spaced Well Average vs LPI UWC/MWC Type Curve; 2The Wider-Spaced Well Average includes 65 wells developed on LPI’s Established Acreage using optimized completions. It excludes the W. Glasscock Cook Package Average (5 wells), which was developed on LPI’s Western Glasscock Acreage using optimized completions; 3UWC/MWC 1.3 MMBOE type curve (400 MBO) representative of a 10,000’ well, utilizing a 1.2 b-factor; Chart lines show cumulative oil production for all wider-spaced wells, normalized to a 10,000’ lateral, 9 as of 8-23-2020
Active Derivatives Strategy Manages Price Risk and Supports Cash Flow Bal-201 Hedged Product Volumes (MBOE) FY-21 Hedged Product Volumes (MBOE) 5,000 10,000 4,413 8,085 8,000 4,000 3,465 7,087 3,000 6,000 2,000 4,000 1,288 2,203 1,000 2,000 0 0 Oil Natural Gas NGL FY-21 Cash Flow2,3 ($ MM) $500 $400 $300 $200 $100 45% of expected FY-21 oil production fully participates in commodity price increases $0 $25 $30 $35 $40 $45 $50 $55 WTI ($/Bbl) Cash Flow, Including Hedges Cash Flow, Excluding Hedges 1Open positions as of 6-30-20; 2See Appendix for reconciliations and definitions of non-GAAP measures; 3Applicable natural gas 10 strip pricing details can be found in the Appendix; Note: Hedges executed through 9-1-20
Executing on Core Strategies Transforms Development Plans Plan as of May-20 Current Plan $700 $70035 35 33 $600 $600 31 30 $500 $50029 28.4 29.0 28.4 26.8 26.6 27 27.0 $400 $400 26.2 26.0 25 25 $300 $300 23 Capital ($ MM) ($ Capital 21.5 $200 $20021 20.5 20 19 (MBO/d) Production Oil $100 $100 17 $340 $325 $482 $265 $190 $482 - $350 - $350 $0 $015 15 FY-19A FY-20E FY-21E FY-19A FY-20E FY-21E $/Bbl 2020 2021 Hedged Oil Price1 $57.25 $45.50 Capital2 ($ MM) Oil Production (MBO/d) 2020 & 2021 normalized development plans focus on production and Cash Flow3 stability 1Reflects an average of realized hedged pricing and proceeds from contract terminations, when applicable, strip pricing and hedges in place as of 9-1-20. Strip pricing details can be found in the Appendix; 2Capital expectations exclude non-budgeted acquisitions; 3See 11 Appendix for reconciliations and definitions of non-GAAP measures
Long-Term Focus on Minimizing Flaring Protects the Environment 1,400 LPI Flared & Vented Natural Gas 5% LPI flared gas 1,200 Basin-wide gas 4% 0.3% May-20 - July-20 takeaway constraints 1,000 800 3% 600 2% 400 1% 200 (% Gas Production) of (% Flared & Vented Natural GasNatural Vented & Flared Flared & Vented Gas (MMcf) Gas Vented & Flared 0 0% 1Q-18 2Q-18 3Q-18 4Q-18 1Q-19 2Q-19 3Q-19 4Q-19 1Q-20 2Q-20 Flared & Vented Natural Gas Flared & Vented Natural Gas as % of Gas Production 1 40% Permian Flared / Vented Gas vs. Gross Gas Production LPI flared gas is nearly half of the peer 1.6% average over the past two years 30% 20% 10% Peer Wtd.-Avg.: 3.15% 0% Peer LPI 1Source: Rystad Energy as of 7-21-20, 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, NBL, OAS, OVV, OXY, PDCE, PE, PXD, QEP, REI, ROSE, 12 RYDAF, SM, WPX, XEC and XOM
Actively Managing our Balance Sheet and Debt Ratios 2.4x Net Debt to Adj. EBITDA1,2 (as reported) 2.6x Net Debt to Consolidated EBITDAX1 (Credit Agreement calculation) $800 $700 $450 $600 $600 $500 $400 $400 $300 Debt ($ MM) ($ Debt $200 $275 $100 $0 FY-20 FY-21 FY-22 FY-23 FY-24 FY-25 FY-26 FY-27 FY-28 $1.0 B Senior unsecured notes $275 MM Credit Agreement drawn3 ($725 MM Revolver) Expect to reduce net borrowings with Free Cash Flow1 in 2H-20 1See Appendix for reconciliations and definitions of non-GAAP measures 2Includes TTM Adjusted EBITDA and net debt as of 6-30-20 13 3Amount drawn as of 6-30-20
LAREDO PETROLEUM APPENDIX
Increased Activity Accelerates Development of Howard County DUCs 1Q-20A 2Q-20A 3Q-20E 4Q-20E FY-20E Drilling Rigs 4.0 2.4 1.0 1.0 2.1 Spuds 25 17 7 6 55 Accelerated Activity Completion Crews 1.7 0.3 0.3 1.0 0.8 Completions 28 5 0 15 48 Total Capital ($MM) $155 $78 $105 - $115 $340 - $350 Avg. Working Interest 98% Avg. Lateral Length 9,000 Cash Flow1 from additional activity is secured with additional 2021 hedges 15 1See Appendix for reconciliations and definitions of non-GAAP measures
Guidance Production: 3Q-20 4Q-20 FY-20 Total production (MBOE/d) 83.5 - 85.5 78.0 - 80.0 85.5 - 86.5 Oil production (MBO/d) 24.2 - 25.2 20.5 - 21.5 26.2 - 26.8 Average sales price realizations: 3Q-20 (excluding derivatives) Oil (% of WTI) 96% NGL (% of WTI) 21% Natural gas (% of Henry Hub) 54% Other ($ MM): 3Q-20 Net income / (expense) of purchased oil ($4.5) Net midstream income / (expense) $1.2 Operating costs & expenses ($/BOE): 3Q-20 Lease operating expenses $2.75 Production and ad valorem taxes 7.25% (% of oil, NGL and natural gas revenues) Transportation and marketing expenses $1.40 General and administrative expenses (excluding LTIP) $1.40 General and administrative expenses (LTIP cash & non-cash) $0.45 Depletion, depreciation and amortization $6.50 16
Commodity Prices Used for 3Q-20 Realization Guidance Oil: WTI NYMEX Brent ICE ($/Bbl) ($/Bbl) Jul-20 $40.77 $43.24 Aug-20 $41.42 $44.15 Sep-20 $41.79 $44.53 3Q-20 Average $41.32 $43.96 Natural Gas Liquids: C2 C3 IC4 NC4 C5+ Composite ($/Bbl) ($/Bbl) ($/Bbl) ($/Bbl) ($/Bbl) ($/Bbl) Jul-20 $9.07 $20.76 $24.56 $22.21 $28.69 $17.13 Aug-20 $9.03 $22.05 $29.40 $22.31 $33.92 $18.27 Sep-20 $9.16 $21.45 $30.08 $22.37 $34.18 $18.18 3Q-20 Average $9.09 $21.42 $27.99 $22.29 $32.24 $17.86 Natural Gas: HH Waha ($/MMBtu) ($/MMBtu) Jul-20 $1.50 $1.33 Aug-20 $1.85 $1.30 Sep-20 $2.10 $1.55 3Q-20 Average $1.81 $1.39 17 Note: Pricing assumptions as of 8-3-20
Strip Pricing WTI Brent HH ($/Bbl) ($/Bbl) ($/MMBtu) Bal-20 $41.45 $44.60 $2.45 FY-21 $43.40 $46.90 $2.75 FY-22 $44.80 $48.85 $2.55 18 Note: Utilizing 8-3-20 strip pricing
Oil, Natural Gas & Natural Gas Liquids Hedges Hedge Product Summary Bal-20 FY-21 FY-22 Oil total volume (Bbl) 4,413,220 8,084,750 3,759,500 Oil wtd-avg price ($/Bbl) - WTI $59.40 Oil wtd-avg price ($/Bbl) - Brent $63.07 $50.80 $47.05 Nat gas total volume (MMBtu) 20,787,000 42,522,500 Nat gas wtd-avg price ($/MMBtu) - HH $2.66 $2.59 NGL total volume (Bbl) 1,288,000 2,202,775 Oil Bal-20 FY-21 FY-22 Natural Gas Liquids Swaps Bal-20 FY-21 FY-22 WTI Swaps Ethane Volume (Bbl) 3,217,220 Volume (Bbl) 184,000 912,500 Wtd-avg price ($/Bbl) $59.40 Wtd-avg price ($/Bbl) $13.60 $12.01 Brent Swaps Propane Volume (Bbl) 1,196,000 5,037,000 3,759,500 Volume (Bbl) 625,600 730,000 Wtd-avg price ($/Bbl) $63.07 $49.43 $47.05 Wtd-avg price ($/Bbl) $26.58 $25.52 Brent Puts Normal Butane Volume (Bbl) 2,463,750 Volume (Bbl) 220,800 255,500 Wtd-avg floor price ($/Bbl) $55.00 Wtd-avg price ($/Bbl) $28.69 $27.72 Brent Collars Isobutane Volume (Bbl) 584,000 Volume (Bbl) 55,200 67,525 Wtd-avg floor price ($/Bbl) $45.00 Wtd-avg price ($/Bbl) $29.99 $28.79 Wtd-avg ceiling price Natural Gasoline $59.50 ($/Bbl) 202,400 237,250 Oil Basis Swaps Bal-20 FY-21 FY-22 Volume (Bbl) Wtd-avg price ($/Bbl) $45.15 $44.31 Brent/WTI Volume (Bbl) 1,803,200 Basis Swaps Bal-20 FY-21 FY-22 Wtd-avg price ($/Bbl) $5.09 Waha/HH Natural Gas Swaps Bal-20 FY-21 FY-22 Volume (MMBtu) 21,160,000 41,610,000 7,300,000 HH Wtd-avg price ($/MMBtu) ($0.82) ($0.55) ($0.53) Volume (MMBtu) 20,787,0001 42,522,500 Wtd-avg price ($/MMBtu) $2.66 $2.59 1Includes 65,000 MMBtu/d in Jul-20, Aug-20 & Dec-20 and 162,000 MMBtu/d in Sep-20 - Nov-20 Note: Open positions as of 6-30-20, hedges executed through 9-1-20 19 Natural gas liquids consist of Mt. Belvieu purity ethane and Mt. Belvieu non-TET propane, normal butane, isobutane, and natural gasoline
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): Three months ended, (in thousands, unaudited) 9/30/19 12/31/19 3/31/201 6/30/20 Net income (loss) ($264,629) ($241,721) $74,646 ($545,455) Plus: Share-settled equity-based compensation, net (1,739) 3,046 2,376 1,694 Depletion, depreciation and amortization 69,099 67,846 61,302 66,574 Impairment expense 397,890 222,999 186,699 406,448 Organizational restructuring expense 5,965 — — 4,200 Mark-to-market on derivatives: (Gain) loss on derivatives, net (96,684) 57,562 (297,836) 90,537 Settlements received (paid) for matured derivatives, net 25,245 14,394 47,723 86,872 Settlements paid for early terminations of derivatives, net — — — — Premiums paid for derivatives (1,415) (1,399) (477) — Accretion expense 1,005 1,041 1,106 1,117 (Gain) loss on disposal of assets, net (1,294) (67) 602 (152) Interest expense 15,191 15,044 24,970 27,072 Loss on extinguishment of debt — — 13,320 — Write-off of debt issuance costs — 935 — 1,103 Income tax (benefit) expense (2,467) (1,776) 2,417 (7,173) Adjusted EBITDA $146,167 $137,904 $116,848 $132,837 20 1Reflects revised and restated figures in 1Q-20 10-Q/A
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): Three months ended, (in thousands, unaudited) 9/30/2019 12/31/2019 3/31/20201 6/30/2020 Net income (loss) ($264,629) ($241,721) $74,646 ($545,455) Organizational restructuring expenses 5,965 - - 4,200 Loss on early redemption of debt - - 13,320 - (Gain) loss on disposal of assets, net (1,294) (67) 602 (152) Consolidated Net Income (Loss) (259,958) (241,788) 88,568 (541,407) Mark-to-market on derivatives: (Gain) loss on derivatives, net (96,684) 57,562 (297,836) 90,537 Settlements received (paid) for matured commodity derivatives, net 25,245 14,394 47,723 86,872 Settlements received (paid) for early terminations of commodity derivatives, net - - - - Mark-to-market (gain) loss on derivatives, net (71,439) 71,956 (250,113) 177,409 Premiums paid for commodity derivatives (1,415) (1,399) (477) (50,593) Non-Cash Charges/Income: Deferred income tax expense (benefit) (2,467) (1,776) 2,417 (7,173) Depletion, depreciation and amortization 69,099 67,846 61,302 66,574 Share-settled equity-based compensation, net (1,739) 3,046 2,376 1,694 Accretion expense 1,005 1,041 1,106 1,117 Impairment expense 397,890 222,999 186,699 406,448 Write-off of debt issuance costs - 935 - 1,103 Interest Expense 15,191 15,044 24,970 27,072 Consolidated EBITDAX after EBITDAX Adjustments (limited to 15%) $146,167 $137,904 $116,848 $82,244 21 1Reflects revised and restated figures in 1Q-20 10-Q/A
Supplemental Non-GAAP Financial Measures 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. 22