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): November 4, 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:
| 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 2.02. Results of Operations and Financial Condition.
On November 4, 2020, Laredo Petroleum, Inc. (the "Company") announced its financial and operating results for the quarter ended September 30, 2020. Copies of the Company's press release and Presentation (as defined below) are furnished as Exhibits 99.1 and 99.2, respectively, to this Current Report on Form 8-K and are incorporated herein by reference.
The Company plans to host a teleconference and webcast on November 5, 2020 at 7:30 am Central Time to discuss these results. To access the call, please dial 1.877.930.8286 or 1.253.336.8309 for international callers, and use conference code 2755456. A replay of the call will be available through Thursday, November 12, 2020, by dialing 1.855.859.2056, and using conference code 2755456. The webcast may be accessed at the Company's website, www.laredopetro.com, under the tab "Investor Relations."
In accordance with General Instruction B.2 of the Form 8-K, the information furnished under this Item 2.02 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 Securities Exchange Act of 1934, as amended (the "Exchange Act"), or otherwise subject to the liabilities of that section, nor shall such information and exhibits be deemed incorporated by reference in any filing under the Securities Act of 1933, as amended (the "Securities Act"), or the Exchange Act.
Item 7.01. Regulation FD Disclosure.
On November 4, 2020, the Company furnished the press release described above in Item 2.02 of this Current Report on Form 8-K. The press release is attached hereto as Exhibit 99.1 and incorporated into this Item 7.01 by reference.
On November 4, 2020, the Company also posted to its website a corporate presentation (the "Presentation"). The Presentation is available on the Company's website, www.laredopetro.com, and is attached hereto as Exhibit 99.2 and incorporated into this Item 7.01 by reference.
All statements in the press release, teleconference and 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 and Section 21E of 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 filings with the SEC for a discussion of 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 the 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 and exhibit be deemed incorporated by reference in 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: November 4, 2020 | By: | /s/ Bryan J. Lemmerman | ||||||
| Bryan J. Lemmerman | ||||||||
| Senior Vice President and Chief Financial Officer | ||||||||
EXHIBIT 99.1
15 West 6th Street, Suite 900 · Tulsa, Oklahoma 74119 · (918) 513-4570 · Fax: (918) 513-4571
www.laredopetro.com
Laredo Petroleum Announces Third-Quarter 2020 Financial and Operating Results
Increases Oil and Total Production Guidance for Fourth-Quarter and Full-Year 2020
TULSA, OK - November 4, 2020 - Laredo Petroleum, Inc. (NYSE: LPI) ("Laredo" or "the Company") today announced its third-quarter 2020 results. For the third quarter of 2020, the Company reported a net loss attributable to common stockholders of $237.4 million, or $20.32 per diluted share. Adjusted Net Income, a non-GAAP financial measure, for the third quarter of 2020 was $47.0 million, or $4.02 per adjusted diluted share. Adjusted EBITDA, a non-GAAP financial measure, for the third quarter of 2020 was $137.3 million.
Please see supplemental financial information at the end of this news release for reconciliations of non-GAAP financial measures, including a calculation of Adjusted EBITDA, Adjusted Net Income and Free Cash Flow.
Third-Quarter 2020 Highlights
•Generated Free Cash Flow, a non-GAAP financial measure, of $71 million and reduced net debt, a non-GAAP financial measure, by $64 million during third-quarter 2020
•Received $58.2 million from settlements of matured/terminated commodity derivatives, resulting in an average hedged sales price of $22.76 per barrel of oil equivalent ("BOE"), a 39% increase versus an average unhedged sales price of $16.39 per BOE in the same period
•Added 6,800 barrels of oil per day ("BOPD") of 2021 oil hedges at a weighted-average swap price of $45.55 Brent, increasing 2021 oil hedges to 22,150 BOPD, equivalent to 80% of anticipated 2021 oil production
•Lowered lease operating expenses ("LOE") to $2.45 per BOE, an 18% decrease from third-quarter 2019
•Reduced general and administrative expenses ("G&A"), excluding long-term incentive plan ("LTIP"), to $1.16 per BOE, a 21% decrease from third-quarter 2019
•Produced an average of 25,120 BOPD and total production of 87,857 BOE per day, a decrease of 10% and an increase of 7%, respectively, from third-quarter 2019, while reducing drilling and completions capital expenditures by 54% during the same period
"Since launching our revised strategy a year ago, the Laredo team has delivered on our core objectives of operational excellence, financial risk management and inventory expansion, and this quarter was no exception," commented Jason Pigott, President and Chief Executive Officer. "We began completions operations in Howard County and did not miss a beat operationally, continuing our exemplary run of efficiency gains and proving we can maintain our low drilling and completions costs in a new area. We generated $71 million in Free Cash Flow, supported by our robust hedge position, enabling us to reduce debt and increase liquidity, and added more hedges in 2021 to further protect future cash flows. We have also increased fourth-quarter and full-year 2020 oil
EXHIBIT 99.1
and total production guidance while maintaining our full-year capital expenditure guidance as our base production continued to outperform expectations during the third quarter."
"In October, we closed on a bolt-on transaction in Howard County, lengthening our runway of higher-margin development opportunities, and our bank group reaffirmed our $725 million borrowing base," continued Mr. Pigott. "We have built tremendous momentum in our business that we expect to carry into 2021 as we bring on our first package of wells in Howard County, execute a continuous development plan within cash flow and focus on further expanding our inventory of high-return locations in Howard County."
Operations Summary
During third-quarter 2020, Laredo resumed completions operations, deploying a completions crew in Howard County. The crew is currently operating on a 15-well package that is expected to be fully online in early December. To date, the transition of the Company's operations to Howard County has exceeded expectations as both drilling and completions efficiencies have set Company records and well costs are tracking to initial estimates of $550 per foot.
Laredo produced 87,857 BOE per day in the third quarter of 2020, including oil production of 25,120 BOPD, with both figures exceeding the midpoint of guidance. Oil production results were driven by continued improvement of the Company's first package of wells on its western Glasscock County acreage, acquired in December 2019.
The Company is currently operating one drilling rig and one completions crew, both located in Howard County, and expects to complete 15 wells during fourth-quarter 2020.
Expenses
Laredo continues to stringently manage cash expenses, maintaining a peer-leading cost structure. During third-quarter 2020, the Company reduced combined unit LOE and cash G&A expenses to $3.61 per BOE, a reduction of 19% from third-quarter 2019.
Laredo has transitioned to selling almost all of its production at Gulf Coast pricing, which the Company believes provides a long-term pricing advantage versus the Midland market. As such, transportation and marketing expenses, reflecting costs associated with transporting the Company's produced oil to the US Gulf Coast and expected deficiency payments related to minimum transportation volume commitments, increased to $1.63 per BOE in third-quarter 2020 compared to $0.74 per BOE in third-quarter 2019 as more produced oil was transported to the US Gulf Coast and the Company expensed anticipated future deficiency payments.
Third-Quarter and Full-Year 2020 Costs Incurred
During the third quarter of 2020, total costs incurred were $43 million, comprised of $31 million in drilling and completions activities, $2 million in land, exploration and data related costs, $4 million in infrastructure, including Laredo Midstream Services investments, and $6 million in other capitalized costs.
Through the first nine months of 2020, excluding non-budgeted acquisitions, total costs incurred were $276 million. The Company expects total costs incurred in the fourth quarter of 2020 to be in a range of $64 to $74 million and remain on track to be within Laredo's full-year 2020 budget of $340 to $350 million.
2
EXHIBIT 99.1
Increased Oil Hedges
For the remainder of 2020, Laredo has hedged 2.1 million barrels of oil, with 1.5 million barrels of oil swapped at a weighted-average price of $59.35 WTI per barrel and 0.6 million barrels of oil swapped at a weighted-average price of $63.07 Brent per barrel. For 2021, the Company has hedged 80% of expected oil production, with 8.1 million barrels of oil at a weighted-average floor price of $50.80 Brent per barrel.
Please see the table in the appendix of Laredo's Third-Quarter 2020 Earnings Presentation posted to the Company's website for the full details of the Company's commodity derivatives.
Liquidity
At September 30, 2020, the Company had outstanding borrowings of $235 million on its $725 million senior secured credit facility, resulting in available capacity, after the reduction for outstanding letters of credit, of $446 million. Including cash and cash equivalents of $40 million, total liquidity was $486 million.
At November 2, 2020, the Company had outstanding borrowings of $220 million on its $725 million senior secured credit facility, resulting in available capacity, after the reduction for outstanding letters of credit, of $461 million. Including cash and cash equivalents of $28 million, total liquidity was $489 million.
Fourth-Quarter and Full-Year 2020 Guidance
The table below reflects the Company's increased fourth-quarter and full-year guidance for total and oil production for 2020. The increase in total production guidance for fourth-quarter and full-year 2020 reflects the continued outperformance versus expectations of natural gas production on the Company's established acreage position. This represent an 8% increase at the midpoint from full-year 2020 guidance issued with first-quarter 2020 results and a 2% increase from full-year 2020 guidance issued with second-quarter 2020 results. The Company raised the low-end of oil production guidance by 2%, compared to previous guidance issued with second-quarter 2020 results, for both fourth-quarter and full-year 2020 as established acreage wells have continued to perform better than type-curve expectations and the performance of the five-well Western Glasscock package has improved. The increase in the high-end of guidance includes the possibility of the Company's 15-well package in Howard County beginning to produce oil prior to the end of 2020.
| 4Q-20E | FY-20E | |||||||||||||
| Total production (MBOE per day) | 82.0 - 84.0 | 87.6 - 88.1 | ||||||||||||
| Oil production (MBOPD) | 21.0 - 23.0 | 26.6 - 27.1 | ||||||||||||
The table below reflects the Company's guidance for selected revenue and expense items for the fourth quarter of 2020.
3
EXHIBIT 99.1
| 4Q-20E | ||||||||
| Average sales price realizations (excluding derivatives): | ||||||||
| Oil (% of WTI) | 95% | |||||||
| NGL (% of WTI) | 26% | |||||||
| Natural gas (% of Henry Hub) | 49% | |||||||
| Other ($ MM): | ||||||||
| Net income (expense) of purchased oil | ($4.3) | |||||||
| Net midstream service income (expense) | $0.75 | |||||||
| Selected average costs & expenses: | ||||||||
| Lease operating expenses ($/BOE) | $2.80 | |||||||
| Production and ad valorem taxes (% of oil, NGL and natural gas sales revenues) | 7.25% | |||||||
| Transportation and marketing expenses ($/BOE) | $1.95 | |||||||
| General and administrative expenses (excluding LTIP, $/BOE) | $1.25 | |||||||
| General and administrative expenses (LTIP cash and non-cash, $/BOE) | $0.35 | |||||||
| Depletion, depreciation and amortization ($/BOE) | $6.00 | |||||||
Conference Call Details
On Thursday, November 5, 2020, at 7:30 a.m. CT, Laredo will host a conference call to discuss its third-quarter 2020 financial and operating results and management's outlook, the content of which is not part of this earnings release. A slide presentation providing summary financial and statistical information that will be discussed on the call will be posted to the Company's website and available for review. The Company invites interested parties to listen to the call via the Company's website at www.laredopetro.com, under the tab for "Investor Relations." Portfolio managers and analysts who would like to participate on the call should dial 877.930.8286 (international dial-in 253.336.8309), using conference code 2755456, 10 minutes prior to the scheduled conference time. A telephonic replay will be available two hours after the call on November 5, 2020 through Thursday, November 12, 2020. Participants may access this replay by dialing 855.859.2056, using conference code 2755456.
About Laredo
Laredo Petroleum, Inc. is an independent energy company with headquarters in Tulsa, Oklahoma. Laredo's business strategy is focused on the acquisition, exploration and development of oil and natural gas properties, primarily in the Permian Basin of West Texas.
Additional information about Laredo may be found on its website at www.laredopetro.com.
4
EXHIBIT 99.1
Forward-Looking Statements
This press release and any oral statements made regarding the contents of this release, including in the conference call referenced herein, contain 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 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 press release and the conference call, 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
5
EXHIBIT 99.1
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 press release and any accompanying disclosures include 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 supplemental financial information at the end of this press release.
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 press release are rounded and therefore approximate.
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.
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. Management believes Free Cash Flow is useful to management and investors in evaluating the operating trends in its business due to 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.
6
EXHIBIT 99.1
Laredo Petroleum, Inc.
Selected operating data
| Three months ended September 30, | Nine months ended September 30, | |||||||||||||||||||||||||
| 2020 | 2019 | 2020 | 2019 | |||||||||||||||||||||||
| (unaudited) | (unaudited) | |||||||||||||||||||||||||
| Sales volumes: | ||||||||||||||||||||||||||
| Oil (MBbl) | 2,311 | 2,560 | 7,809 | 7,865 | ||||||||||||||||||||||
| NGL (MBbl) | 2,760 | 2,344 | 7,979 | 6,643 | ||||||||||||||||||||||
| Natural gas (MMcf) | 18,072 | 15,790 | 52,401 | 43,731 | ||||||||||||||||||||||
Oil equivalents (MBOE)(1)(2) | 8,083 | 7,537 | 24,522 | 21,797 | ||||||||||||||||||||||
Average daily oil equivalent sales volumes (BOE/D)(2) | 87,857 | 81,921 | 89,496 | 79,843 | ||||||||||||||||||||||
Average daily oil sales volumes (BOPD)(2) | 25,120 | 27,830 | 28,500 | 28,810 | ||||||||||||||||||||||
Average sales prices(2): | ||||||||||||||||||||||||||
Oil ($/Bbl)(3) | $ | 40.38 | $ | 55.35 | $ | 36.29 | $ | 54.79 | ||||||||||||||||||
NGL ($/Bbl)(3) | $ | 9.04 | $ | 8.75 | $ | 6.23 | $ | 11.28 | ||||||||||||||||||
Natural gas ($/Mcf)(3) | $ | 0.79 | $ | 0.48 | $ | 0.56 | $ | 0.48 | ||||||||||||||||||
Average sales price ($/BOE)(3) | $ | 16.39 | $ | 22.52 | $ | 14.78 | $ | 24.18 | ||||||||||||||||||
Oil, with commodity derivatives ($/Bbl)(4) | $ | 59.93 | $ | 56.15 | $ | 55.35 | $ | 53.59 | ||||||||||||||||||
NGL, with commodity derivatives ($/Bbl)(4) | $ | 10.46 | $ | 13.43 | $ | 8.35 | $ | 13.83 | ||||||||||||||||||
Natural gas, with commodity derivatives ($/Mcf)(4) | $ | 0.92 | $ | 1.01 | $ | 0.92 | $ | 1.09 | ||||||||||||||||||
Average sales price, with commodity derivatives ($/BOE)(4) | $ | 22.76 | $ | 25.38 | $ | 22.32 | $ | 25.75 | ||||||||||||||||||
Selected average costs and expenses per BOE sold(2): | ||||||||||||||||||||||||||
| Lease operating expenses | $ | 2.45 | $ | 3.00 | $ | 2.55 | $ | 3.16 | ||||||||||||||||||
| Production and ad valorem taxes | 1.08 | 1.47 | 1.02 | 1.36 | ||||||||||||||||||||||
| Transportation and marketing expenses | 1.63 | 0.74 | 1.54 | 0.70 | ||||||||||||||||||||||
| Midstream service expenses | 0.13 | 0.16 | 0.12 | 0.16 | ||||||||||||||||||||||
| General and administrative (excluding LTIP) | 1.16 | 1.46 | 1.16 | 1.72 | ||||||||||||||||||||||
| Total selected operating expenses | $ | 6.45 | $ | 6.83 | $ | 6.39 | $ | 7.10 | ||||||||||||||||||
| General and administrative (LTIP): | ||||||||||||||||||||||||||
| LTIP cash | $ | 0.03 | $ | — | $ | 0.04 | $ | — | ||||||||||||||||||
| LTIP non-cash | $ | 0.23 | $ | (0.28) | $ | 0.22 | $ | 0.18 | ||||||||||||||||||
| Depletion, depreciation and amortization | $ | 5.82 | $ | 9.17 | $ | 7.13 | $ | 9.08 | ||||||||||||||||||
_______________________________________________________________________________
(1)BOE is calculated using a conversion rate of six Mcf per one Bbl.
(2)The numbers presented are calculated based on actual amounts that are not rounded.
(3)Price reflects the average of actual sales prices received when control passes to the purchaser/customer adjusted for quality, certain transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the delivery point.
(4)Price reflects the after-effects of the Company's commodity derivative transactions on it's average sales prices. The Company's calculation of such after-effects includes settlements of matured commodity derivatives during the respective periods in accordance with GAAP and an adjustment to reflect premiums incurred previously or upon settlement that are attributable to commodity derivatives that settled during the respective periods.
7
EXHIBIT 99.1
Laredo Petroleum, Inc.
Condensed consolidated statements of operations
| Three months ended September 30, | Nine months ended September 30, | |||||||||||||||||||||||||
| (in thousands, except per share data) | 2020 | 2019 | 2020 | 2019 | ||||||||||||||||||||||
| (unaudited) | (unaudited) | |||||||||||||||||||||||||
| Revenues: | ||||||||||||||||||||||||||
| Oil, NGL and natural gas sales | $ | 132,462 | $ | 169,751 | $ | 362,490 | $ | 526,990 | ||||||||||||||||||
| Midstream service revenues | 1,751 | 3,079 | 6,715 | 8,572 | ||||||||||||||||||||||
| Sales of purchased oil | 39,334 | 20,739 | 119,922 | 83,597 | ||||||||||||||||||||||
| Total revenues | 173,547 | 193,569 | 489,127 | 619,159 | ||||||||||||||||||||||
| Costs and expenses: | ||||||||||||||||||||||||||
| Lease operating expenses | 19,840 | 22,597 | 62,471 | 68,838 | ||||||||||||||||||||||
| Production and ad valorem taxes | 8,753 | 11,085 | 24,935 | 29,632 | ||||||||||||||||||||||
| Transportation and marketing expenses | 13,161 | 5,583 | 37,886 | 15,233 | ||||||||||||||||||||||
| Midstream service expenses | 1,073 | 1,191 | 3,058 | 3,401 | ||||||||||||||||||||||
| Costs of purchased oil | 42,720 | 20,741 | 138,134 | 83,604 | ||||||||||||||||||||||
| General and administrative | 11,473 | 8,852 | 34,694 | 41,427 | ||||||||||||||||||||||
| Organizational restructuring expenses | — | 5,965 | 4,200 | 16,371 | ||||||||||||||||||||||
| Depletion, depreciation and amortization | 47,015 | 69,099 | 174,891 | 197,900 | ||||||||||||||||||||||
| Impairment expense | 196,088 | 397,890 | 789,235 | 397,890 | ||||||||||||||||||||||
| Other operating expenses | 1,102 | 1,005 | 3,325 | 3,077 | ||||||||||||||||||||||
| Total costs and expenses | 341,225 | 544,008 | 1,272,829 | 857,373 | ||||||||||||||||||||||
| Operating loss | (167,678) | (350,439) | (783,702) | (238,214) | ||||||||||||||||||||||
| Non-operating income (expense): | ||||||||||||||||||||||||||
| Gain (loss) on derivatives, net | (45,250) | 96,684 | 162,049 | 136,713 | ||||||||||||||||||||||
| Interest expense | (26,828) | (15,191) | (78,870) | (46,503) | ||||||||||||||||||||||
| Litigation settlement | — | — | — | 42,500 | ||||||||||||||||||||||
| Loss on extinguishment of debt | — | — | (13,320) | — | ||||||||||||||||||||||
| Other, net | (74) | 1,850 | (1,552) | 3,954 | ||||||||||||||||||||||
| Total non-operating income (expense), net | (72,152) | 83,343 | 68,307 | 136,664 | ||||||||||||||||||||||
Loss before income taxes | (239,830) | (267,096) | (715,395) | (101,550) | ||||||||||||||||||||||
| Income tax benefit: | ||||||||||||||||||||||||||
| Deferred | 2,398 | 2,467 | 7,154 | 812 | ||||||||||||||||||||||
| Total income tax benefit | 2,398 | 2,467 | 7,154 | 812 | ||||||||||||||||||||||
| Net loss | $ | (237,432) | $ | (264,629) | $ | (708,241) | $ | (100,738) | ||||||||||||||||||
Net loss per common share(1): | ||||||||||||||||||||||||||
| Basic | $ | (20.32) | $ | (22.86) | $ | (60.76) | $ | (8.72) | ||||||||||||||||||
| Diluted | $ | (20.32) | $ | (22.86) | $ | (60.76) | $ | (8.72) | ||||||||||||||||||
Weighted-average common shares outstanding(1): | ||||||||||||||||||||||||||
| Basic | 11,686 | 11,578 | 11,657 | 11,558 | ||||||||||||||||||||||
| Diluted | 11,686 | 11,578 | 11,657 | 11,558 | ||||||||||||||||||||||
_______________________________________________________________________________
(1)Net loss per common share and weighted-average common shares outstanding were retroactively adjusted for the Company's 1-for-20 reverse stock split effective June 1, 2020.
8
EXHIBIT 99.1
Laredo Petroleum, Inc.
Condensed consolidated statements of cash flows
| Three months ended September 30, | Nine months ended September 30, | |||||||||||||||||||||||||
| (in thousands) | 2020 | 2019 | 2020 | 2019 | ||||||||||||||||||||||
| (unaudited) | (unaudited) | |||||||||||||||||||||||||
| Cash flows from operating activities: | ||||||||||||||||||||||||||
| Net loss | $ | (237,432) | $ | (264,629) | $ | (708,241) | $ | (100,738) | ||||||||||||||||||
| Adjustments to reconcile net loss to net cash provided by operating activities: | ||||||||||||||||||||||||||
| Share-settled equity-based compensation, net | 2,041 | (1,739) | 6,111 | 5,244 | ||||||||||||||||||||||
| Depletion, depreciation and amortization | 47,015 | 69,099 | 174,891 | 197,900 | ||||||||||||||||||||||
| Impairment expense | 196,088 | 397,890 | 789,235 | 397,890 | ||||||||||||||||||||||
| Mark-to-market on derivatives: | ||||||||||||||||||||||||||
| (Gain) loss on derivatives, net | 45,250 | (96,684) | (162,049) | (136,713) | ||||||||||||||||||||||
| Settlements received for matured derivatives, net | 51,840 | 25,245 | 186,435 | 48,827 | ||||||||||||||||||||||
| Settlements received (paid) for early-terminated commodity derivatives, net | 6,340 | — | 6,340 | (5,409) | ||||||||||||||||||||||
| Premiums paid for commodity derivatives | — | (1,415) | (51,070) | (7,664) | ||||||||||||||||||||||
| Loss on extinguishment of debt | — | — | 13,320 | — | ||||||||||||||||||||||
| Deferred income tax benefit | (2,398) | (2,467) | (7,154) | (812) | ||||||||||||||||||||||
| Other, net | 5,099 | 2,606 | 17,956 | 14,795 | ||||||||||||||||||||||
| Cash flows from operating activities before changes in operating assets and liabilities, net | 113,843 | 127,906 | 265,774 | 413,320 | ||||||||||||||||||||||
| Change in current assets and liabilities, net | (8,360) | (21,183) | 19,098 | (48,305) | ||||||||||||||||||||||
| Change in noncurrent assets and liabilities, net | (3,425) | (1,124) | (11,252) | 1,853 | ||||||||||||||||||||||
| Net cash provided by operating activities | 102,058 | 105,599 | 273,620 | 366,868 | ||||||||||||||||||||||
| Cash flows from investing activities: | ||||||||||||||||||||||||||
| Acquisitions of oil and natural gas properties, net | — | — | (23,563) | (2,880) | ||||||||||||||||||||||
| Capital expenditures: | ||||||||||||||||||||||||||
| Oil and natural gas properties | (36,338) | (83,566) | (278,277) | (368,182) | ||||||||||||||||||||||
| Midstream service assets | (756) | (1,292) | (2,517) | (6,741) | ||||||||||||||||||||||
| Other fixed assets | (955) | (755) | (3,024) | (1,720) | ||||||||||||||||||||||
| Proceeds from dispositions of capital assets, net of selling costs | 514 | 5,911 | 1,242 | 6,847 | ||||||||||||||||||||||
| Net cash used in investing activities | (37,535) | (79,702) | (306,139) | (372,676) | ||||||||||||||||||||||
| Cash flows from financing activities: | ||||||||||||||||||||||||||
| Borrowings on Senior Secured Credit Facility | 45,000 | — | 45,000 | 80,000 | ||||||||||||||||||||||
| Payments on Senior Secured Credit Facility | (85,000) | (50,000) | (185,000) | (85,000) | ||||||||||||||||||||||
| Issuance of January 2025 Notes and January 2028 Notes | — | — | 1,000,000 | — | ||||||||||||||||||||||
| Extinguishment of debt | — | — | (808,855) | — | ||||||||||||||||||||||
| Payments for debt issuance costs | — | — | (18,451) | — | ||||||||||||||||||||||
| Other, net | (12) | (4) | (774) | (2,650) | ||||||||||||||||||||||
| Net cash (used in) provided by financing activities | (40,012) | (50,004) | 31,920 | (7,650) | ||||||||||||||||||||||
| Net increase (decrease) in cash and cash equivalents | 24,511 | (24,107) | (599) | (13,458) | ||||||||||||||||||||||
| Cash and cash equivalents, beginning of period | 15,747 | 55,800 | 40,857 | 45,151 | ||||||||||||||||||||||
| Cash and cash equivalents, end of period | $ | 40,258 | $ | 31,693 | $ | 40,258 | $ | 31,693 | ||||||||||||||||||
9
EXHIBIT 99.1
Laredo Petroleum, Inc.
Total Costs Incurred
The following table presents the components of the Company's costs incurred, excluding non-budgeted acquisition costs, for the periods presented:
| Three months ended September 30, | Nine months ended September 30, | |||||||||||||||||||||||||
| (in thousands) | 2020 | 2019 | 2020 | 2019 | ||||||||||||||||||||||
| (unaudited) | (unaudited) | |||||||||||||||||||||||||
| Oil and natural gas properties | $ | 41,128 | $ | 76,837 | $ | 269,937 | $ | 365,839 | ||||||||||||||||||
| Midstream service assets | 1,103 | 1,147 | 2,697 | 7,584 | ||||||||||||||||||||||
| Other fixed assets | 495 | 999 | 3,092 | 1,966 | ||||||||||||||||||||||
| Total costs incurred, excluding non-budgeted acquisition costs | $ | 42,726 | $ | 78,983 | $ | 275,726 | $ | 375,389 | ||||||||||||||||||
10
EXHIBIT 99.1
Laredo Petroleum, Inc.
Supplemental reconciliations of GAAP to non-GAAP financial measures
Non-GAAP financial measures
The non-GAAP financial measures of Free Cash Flow, Adjusted Net Income and Adjusted EBITDA, as defined by the Company, may not be comparable to similarly titled measures used by other companies. Therefore, these non-GAAP financial measures should be considered in conjunction with net income or loss and other performance measures prepared in accordance with GAAP, such as operating income or loss or cash flows from operating activities. Free Cash Flow, Adjusted Net Income and Adjusted EBITDA should not be considered in isolation or as a substitute for GAAP measures, such as net income or loss, operating income or loss or any other GAAP measure of liquidity or financial performance.
Free Cash Flow (Unaudited)
Free Cash Flow, a non-GAAP financial measure, 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 the Company's business that are affected by production, commodity prices, operating costs and other related factors. There are significant limitations to the use of Free Cash Flow as a measure of performance, including the lack of comparability due to the different methods of calculating Free Cash Flow reported by different companies.
The following table presents a reconciliation of net cash provided by operating activities (GAAP) to cash flows from operating activities before changes in operating assets and liabilities, net, less costs incurred, excluding non-budgeted acquisition costs, for the calculation of Free Cash Flow (non-GAAP) for the periods presented:
| Three months ended September 30, | Nine months ended September 30, | |||||||||||||||||||||||||
| (in thousands) | 2020 | 2019 | 2020 | 2019 | ||||||||||||||||||||||
| (unaudited) | (unaudited) | |||||||||||||||||||||||||
| Net cash provided by operating activities | $ | 102,058 | $ | 105,599 | $ | 273,620 | $ | 366,868 | ||||||||||||||||||
| Less: | ||||||||||||||||||||||||||
| Change in current assets and liabilities, net | (8,360) | (21,183) | 19,098 | (48,305) | ||||||||||||||||||||||
| Change in noncurrent assets and liabilities, net | (3,425) | (1,124) | (11,252) | 1,853 | ||||||||||||||||||||||
| Cash flows from operating activities before changes in operating assets and liabilities, net | 113,843 | 127,906 | 265,774 | 413,320 | ||||||||||||||||||||||
| Less costs incurred, excluding non-budgeted acquisition costs: | ||||||||||||||||||||||||||
Oil and natural gas properties(1) | 41,128 | 76,837 | 269,937 | 365,839 | ||||||||||||||||||||||
Midstream service assets(1) | 1,103 | 1,147 | 2,697 | 7,584 | ||||||||||||||||||||||
| Other fixed assets | 495 | 999 | 3,092 | 1,966 | ||||||||||||||||||||||
| Total costs incurred, excluding non-budgeted acquisition costs | 42,726 | 78,983 | 275,726 | 375,389 | ||||||||||||||||||||||
| Free Cash Flow (non-GAAP) | $ | 71,117 | $ | 48,923 | $ | (9,952) | $ | 37,931 | ||||||||||||||||||
_____________________________________________________________________________
(1)Includes capitalized share-settled equity-based compensation and asset retirement costs.
11
EXHIBIT 99.1
Adjusted Net Income (Unaudited)
Adjusted Net Income is a non-GAAP financial measure that the Company defines as income or loss before income taxes plus adjustments for mark-to-market on derivatives, premiums paid for commodity derivatives that matured during the period, impairment expense, gains or losses on disposal of assets, other non-recurring income and expenses and adjusted income tax expense. The Company believes Adjusted Net Income helps investors in the oil and natural gas industry to measure and compare the Company's performance to other oil and natural gas companies by excluding from the calculation items that can vary significantly from company to company depending upon accounting methods, the book value of assets and other non-operational factors.
The following table presents a reconciliation of loss before income taxes (GAAP) to Adjusted Net Income (non-GAAP):
| Three months ended September 30, | Nine months ended September 30, | |||||||||||||||||||||||||
| (in thousands, except per share data) | 2020 | 2019 | 2020 | 2019 | ||||||||||||||||||||||
| (unaudited) | (unaudited) | |||||||||||||||||||||||||
Loss before income taxes | $ | (239,830) | $ | (267,096) | $ | (715,395) | $ | (101,550) | ||||||||||||||||||
| Plus: | ||||||||||||||||||||||||||
| Mark-to-market on derivatives: | ||||||||||||||||||||||||||
| (Gain) loss on derivatives, net | 45,250 | (96,684) | (162,049) | (136,713) | ||||||||||||||||||||||
| Settlements received for matured derivatives, net | 51,840 | 25,245 | 186,435 | 48,827 | ||||||||||||||||||||||
| Settlements received (paid) for early-terminated commodity derivatives, net | 6,340 | — | 6,340 | (5,409) | ||||||||||||||||||||||
Premiums paid for commodity derivatives that matured during the period(1) | — | (1,415) | (477) | (7,664) | ||||||||||||||||||||||
| Organizational restructuring expenses | — | 5,965 | 4,200 | 16,371 | ||||||||||||||||||||||
| Impairment expense | 196,088 | 397,890 | 789,235 | 397,890 | ||||||||||||||||||||||
| Loss on extinguishment of debt | — | — | 13,320 | — | ||||||||||||||||||||||
| Litigation settlement | — | — | — | (42,500) | ||||||||||||||||||||||
| (Gain) loss on disposal of assets, net | 607 | (1,294) | 1,057 | 315 | ||||||||||||||||||||||
| Write-off of debt issuance costs | — | — | 1,103 | — | ||||||||||||||||||||||
| Adjusted income before adjusted income tax expense | 60,295 | 62,611 | 123,769 | 169,567 | ||||||||||||||||||||||
Adjusted income tax expense(2) | (13,265) | (13,774) | (27,229) | (37,305) | ||||||||||||||||||||||
| Adjusted Net Income | $ | 47,030 | $ | 48,837 | $ | 96,540 | $ | 132,262 | ||||||||||||||||||
Net loss per common share(3): | ||||||||||||||||||||||||||
| Basic | $ | (20.32) | $ | (22.86) | $ | (60.76) | $ | (8.72) | ||||||||||||||||||
| Diluted | $ | (20.32) | $ | (22.86) | $ | (60.76) | $ | (8.72) | ||||||||||||||||||
Adjusted Net Income per common share(3): | ||||||||||||||||||||||||||
| Basic | $ | 4.02 | $ | 4.22 | $ | 8.28 | $ | 11.44 | ||||||||||||||||||
| Diluted | $ | 4.02 | $ | 4.22 | $ | 8.28 | $ | 11.44 | ||||||||||||||||||
| Adjusted diluted | $ | 4.02 | $ | 4.22 | $ | 8.25 | $ | 11.41 | ||||||||||||||||||
Weighted-average common shares outstanding(3): | ||||||||||||||||||||||||||
| Basic | 11,686 | 11,578 | 11,657 | 11,558 | ||||||||||||||||||||||
| Diluted | 11,686 | 11,578 | 11,657 | 11,558 | ||||||||||||||||||||||
| Adjusted diluted | 11,691 | 11,585 | 11,705 | 11,587 | ||||||||||||||||||||||
_______________________________________________________________________________
(1)Reflects premiums incurred previously or upon settlement that are attributable to derivatives settled in the respective periods presented and were not a result of a hedge restructuring.
(2)Adjusted income tax expense is calculated by applying a statutory tax rate of 22% for each of the periods ended September 30, 2020 and 2019.
(3)Net loss per common share, Adjusted Net Income per common share and weighted-average common shares outstanding were retroactively adjusted for the Company's 1-for-20 reverse stock split effective June 1, 2020.
12
EXHIBIT 99.1
Adjusted EBITDA (Unaudited)
Adjusted EBITDA is a non-GAAP financial measure that the Company defines 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, management believes Adjusted EBITDA is useful to an investor in evaluating the Company's 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 the Company's operations from period to period by removing the effect of its capital structure from its operating structure; and
• is used by management for various purposes, including as a measure of operating performance, in presentations to the Company's 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 the Company's 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. The Company's measurements of Adjusted EBITDA for financial reporting as compared to compliance under its debt agreements differ.
The following table presents a reconciliation of net loss (GAAP) to Adjusted EBITDA (non-GAAP) for the periods presented:
| Three months ended September 30, | Nine months ended September 30, | |||||||||||||||||||||||||
| (in thousands) | 2020 | 2019 | 2020 | 2019 | ||||||||||||||||||||||
| (unaudited) | (unaudited) | |||||||||||||||||||||||||
| Net loss | $ | (237,432) | $ | (264,629) | $ | (708,241) | $ | (100,738) | ||||||||||||||||||
| Plus: | ||||||||||||||||||||||||||
| Share-settled equity-based compensation, net | 2,041 | (1,739) | 6,111 | 5,244 | ||||||||||||||||||||||
| Depletion, depreciation and amortization | 47,015 | 69,099 | 174,891 | 197,900 | ||||||||||||||||||||||
| Impairment expense | 196,088 | 397,890 | 789,235 | 397,890 | ||||||||||||||||||||||
| Organizational restructuring expenses | — | 5,965 | 4,200 | 16,371 | ||||||||||||||||||||||
| Mark-to-market on derivatives: | ||||||||||||||||||||||||||
| (Gain) loss on derivatives, net | 45,250 | (96,684) | (162,049) | (136,713) | ||||||||||||||||||||||
| Settlements received for matured derivatives, net | 51,840 | 25,245 | 186,435 | 48,827 | ||||||||||||||||||||||
| Settlements received (paid) for early-terminated commodity derivatives, net | 6,340 | — | 6,340 | (5,409) | ||||||||||||||||||||||
Premiums paid for commodity derivatives that matured during the period(1) | — | (1,415) | (477) | (7,664) | ||||||||||||||||||||||
| Accretion expense | 1,102 | 1,005 | 3,325 | 3,077 | ||||||||||||||||||||||
| (Gain) loss on disposal of assets, net | 607 | (1,294) | 1,057 | 315 | ||||||||||||||||||||||
| Interest expense | 26,828 | 15,191 | 78,870 | 46,503 | ||||||||||||||||||||||
| Loss on extinguishment of debt | — | — | 13,320 | — | ||||||||||||||||||||||
| Litigation settlement | — | — | — | (42,500) | ||||||||||||||||||||||
| Write-off of debt issuance costs | — | — | 1,103 | — | ||||||||||||||||||||||
| Income tax benefit | (2,398) | (2,467) | (7,154) | (812) | ||||||||||||||||||||||
| Adjusted EBITDA | $ | 137,281 | $ | 146,167 | $ | 386,966 | $ | 422,291 | ||||||||||||||||||
_____________________________________________________________________________
(1)Reflects premiums incurred previously or upon settlement that are attributable to derivatives settled in the respective periods presented and were not a result of a hedge restructuring.
13
EXHIBIT 99.1
# # #
Contacts:
Ron Hagood: 918.858.5504 - RHagood@laredopetro.com
14
EXHIBIT 99.2 Third-Quarter 2020 Earnings 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, 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
Executing Strategy to Increase Stakeholder Value Principles Manage Optimize Expand Financial Risk Existing Asset High-Margin Inventory ▪ Generated $71 MM of Free ▪ Lowered unit LOE 18% ▪ Initiated completion Cash Flow1 in 3Q-20 and Cash G&A 21% from operations on first well 3Q-19 package in Howard ▪ Received $58.2 MM from County settlements of matured / ▪ Set Company record for terminated commodity drilling efficiencies in ▪ Acquired 2,758 additional derivatives in 3Q-20 3Q-20 bolt-on net acres in Howard County in Oct-20 ▪ Reduced Net Debt by ▪ Increased oil and total $67 MM2 since end of production guidance for 2Q-20 FY-20 and reaffirmed capital guidance Objectives Improve Reduce Expand Target Free Oil Cut leverage Margins Cash Flow1 1 See Appendix for reconciliations and definitions of non-GAAP measures 3 2 As of 11-2-2020
Actively Managing our Balance Sheet and Debt Ratios 2.3x Net Debt to Adj. EBITDA1,2 (as reported) 2.5x Net Debt to Consolidated EBITDAX1,2 (Credit Agreement calculation) $28 MM Cash Balance3 $800 $700 $505 $600 $600 $500 $400 $ MM $ $400 $300 $200 $220 $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 $220 MM Credit Agreement drawn3 ($725 MM Revolver) Reduced Net Debt1 by $67 MM since 2Q-20 with further reductions expected by YE-20 1See Appendix for reconciliations and definitions of non-GAAP measures 2Includes TTM Adjusted EBITDA/Consolidated EBITDAX and net debt as of 9-30-20 4 3Amount shown as of 11-2-20
Active Derivatives Strategy Manages Price Risk and Supports Cash Flow Bal-201 Hedged Product Volumes (MBOE) FY-21 Hedged Product Volumes (MBOE) 2,500 10,000 2,108 1,983 8,085 2,000 8,000 7,087 1,500 6,000 1,000 4,000 644 2,203 500 2,000 0 0 Oil Natural Gas NGL 2 $500 FY-21 Cash Flow ($ MM) $400 $300 $200 80% of anticipated 2021 oil $100 volumes hedged at a wtd-avg floor price of $50.80 Brent $0 $25 $30 $35 $40 $45 $50 $55 WTI ($/Bbl) Cash Flow, Including Hedges Cash Flow, Excluding Hedges 5 1Open positions as of 9-30-20; hedges executed through 10-30-20 2 Natural gas price held flat at $3/Mcf
Maintaining Operational & Cost Advantages in Move to Howard County Drilling & Completions Efficiencies 1,600 1,200 Efficiency gains 800 maintained in move to Howard County 400 Feet per Day per Feet 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 3Q-20 Drilled Feet/Day/Rig Fractured Feet/Day/Crew Consistently Reducing DC&E Costs $800 $788 $764 $675 $600 $640 $550 $400 $200 DC&E Cost ($/ft) Cost DC&E $0 FY-17 FY-18 FY-19 1H-20 Current Estimated Cost1 1Based on internal estimates as of 3Q-20 6
Cost-Control Focus Improves Margins Demonstrated History of Expense Reduction $12 $10.66 $10 $8 $7.60 $6.38 $6.07 $6 $4.65 $3.71 ($/BOE) $4 $2 $0 FY-15 FY-16 FY-17 FY-18 FY-19 YTD-2020 Cash G&A Expense1 LOE Peer-Leading Controllable Cash Costs ($/BOE) $8 Peer Avg.: $6.06/BOE $6 $4 $3.61 $/BOE $2 $0 3Q-20 Peers LPI LOE Cash G&A Expense 1 1Excludes long-term incentive plan (“LTIP”) cash & non-cash compensation expenses 7 Note: Peer results are based on most recent public filing and include: CDEV, CPE, ESTE, MTDR, PE, QEP, SM and WPX
Acquisitions Add Oily, High-Margin Inventory ▪ Acquisitions expected to add 3+ Acquired beginning Dec-19 years of high-margin inventory and Howard County Total >1,600 BOE/d of production Net Acres 11,299 Targets LS/UWC/MWC ▪ All development activity has Locations 120 - 155 transitioned to Howard and W. Glasscock counties W. Glasscock County Total ▪ First development package in Net Acres 4,352 Howard County expected to be Targets LS/UWC/MWC online by end of 4Q-20 Locations 45 Acquisition Cost per Undeveloped Acre 20,000 $25 16,000 $20 12,000 $15 8,000 $10 Ac) /M ($ Acquired Acres Net Acquired 4,000 $5 Net Acquisition Cost Acquisition Net 0 $0 1 2 1 2 Dec-19 Dec-19 Feb-20 Apr-20 Oct-20 Total LPI Leasehold (133,710 net acres) Closing Date Acquired Net Acres Net Acquisition Cost ($M/Ac) 1Subject to a previously disclosed potential contingency payment; 2Net purchase price includes an adjustment for acquired production 8 Map, acreage and locations as of 10-16-20
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’ LPI Leasehold to 10,000’, respectively Oct-20 Acquisition ▪ Includes production of 210 BOE/d (80% oil) ▪ Low-cost financing with entire transaction funded by Senior Secured Credit Facility Undeveloped acreage acquired at $2,200/acre1 1Net purchase price includes an adjustment for acquired production 9 Map, acreage and locations as of 10-16-20
Acquired Acreage Driving Future Capital Efficiency 2021 Plan First-Year Cumulative Oil Production vs Well Cost2 $600 35 180 $60 160 $500 $50 30 140 28.4 29.0 $400 27.1 120 $40 27.0 100 ) 26.6 $300 25 $30 Bbl Year Oil Production Oil Year 80 - ($/ Capital ($ MM) ($ Capital $200 60 $20 20 (MBO) Production Oil Year - 40 Oil Production (MBO/d) Production Oil $100 $10 20 First $482 Cost/First Well $0 15 0 $0 FY-19A FY-20E FY-21E Established Western Howard Acreage Glasscock County Capital1 ($ MM) Oil Production (MBO/d) UWC/MWC County 2021 plan focused on Howard County development 1Capital expectations exclude non-budgeted acquisitions 10 2Utilizes current productivity and spacing assumptions; well cost assumptions of $5.5 MM
Committed to Protecting the Environment 1,400 LPI Flared & Vented Natural Gas 5.0% LPI flared 1,200 Basin-wide gas 0.14% gas in 3Q-20 4.0% 1,000 takeaway constraints 800 3.0% 600 2.0% 400 1.0% Vent & Flare Total 200 (% of Total production) Total of (% Flared & Vented Gas (MMcf) Gas Vented & Flared 0 0.0% 1Q-18 2Q-18 3Q-18 4Q-18 1Q-19 2Q-19 3Q-19 4Q-19 1Q-20 2Q-20 3Q-20 Flared & Vented Natural Gas Flared & Vented Natural Gas as % of Gas Production Permian Flared / Vented Gas vs. Gross Gas Production1 40% LPI flared gas is nearly half of the peer 30% 1.5% average over the past two years 20% 10% Peer Wtd.-Avg.: 2.93% 0% Peer LPI 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, 11 RYDAF, SM, WPX, XEC and XOM
Committed to Our Communities >$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 >$570,000 Total amount donated since 2019 to improve our local communities 12
LAREDO PETROLEUM APPENDIX 13
Increased Activity Accelerates Development of Howard County DUCs 1Q-20A 2Q-20A 3Q-20A 4Q-20E FY-20E Drilling Rigs 4.0 2.4 1.0 1.0 2.1 Spuds 25 17 7 6 55 Completion Crews 1.7 0.3 0.3 1.0 0.8 Completions 28 5 0 15 48 Total Capital1 ($MM) $155 $78 $43 $64 - $74 $340 - $350 Avg. Working Interest 98% Avg. Lateral Length 9,000 14 1Excluding non-budgeted acquisitions
Guidance Production: 4Q-20 FY-20 Total production (MBOE/d) 82.0 - 84.0 87.6 - 88.1 Oil production (MBO/d) 21.0 - 23.0 26.6 - 27.1 Average sales price realizations: 4Q-20 (excluding derivatives) Oil (% of WTI) 95% NGL (% of WTI) 26% Natural gas (% of Henry Hub) 49% Other ($ 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 7.25% (% of oil, NGL and natural gas revenues) 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 $6.00 15
Commodity Prices Used for 4Q-20 Realization Guidance Oil: WTI NYMEX Brent ICE ($/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 $40.03 Natural Gas Liquids: C2 C3 IC4 NC4 C5+ Composite ($/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 $19.29 Natural Gas: HH Waha ($/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 $1.95 16 Note: Pricing assumptions as of 11-2-20
Oil, Natural Gas & Natural Gas Liquids Hedges Hedge Product Summary 4Q-20 FY-21 FY-22 Oil total volume (Bbl) 2,107,720 8,084,750 3,759,500 Oil wtd-avg price ($/Bbl) - WTI $59.35 Oil wtd-avg price ($/Bbl) - Brent $63.07 $50.80 $47.05 Nat gas total volume (MMBtu) 11,897,000 42,522,500 Nat gas wtd-avg price ($/MMBtu) - HH $2.65 $2.59 NGL total volume (Bbl) 644,000 2,202,775 Oil 4Q-20 FY-21 FY-22 Natural Gas Liquids Swaps 4Q-20 FY-21 FY-22 WTI Swaps Ethane Volume (Bbl) 1,509,720 Volume (Bbl) 92,000 912,500 Wtd-avg price ($/Bbl) $59.35 Wtd-avg price ($/Bbl) $13.60 $12.01 Brent Swaps Propane Volume (Bbl) 598,000 5,037,000 3,759,500 Volume (Bbl) 312,800 730,000 Wtd-avg price ($/Bbl) $63.07 $49.43 $47.05 Wtd-avg price ($/Bbl) $26.58 $25.52 Brent Puts Normal Butane Volume (Bbl) 2,463,750 Volume (Bbl) 110,400 255,500 Wtd-avg floor price ($/Bbl) $55.00 Wtd-avg price ($/Bbl) $28.69 $27.72 Brent Collars Isobutane Volume (Bbl) 584,000 Volume (Bbl) 27,600 67,525 Wtd-avg floor price ($/Bbl) $45.00 Wtd-avg price ($/Bbl) $29.99 $28.79 Wtd-avg ceiling price ($/Bbl) $59.50 Natural Gasoline Volume (Bbl) 101,200 237,250 Oil Basis Swaps 4Q-20 FY-21 FY-22 Wtd-avg price ($/Bbl) $45.15 $44.31 Brent/WTI Basis Swaps 4Q-20 FY-21 FY-22 Volume (Bbl) 901,600 Waha/HH Wtd-avg price ($/Bbl) $5.09 Volume (MMBtu) 10,580,000 41,610,000 7,300,000 Natural Gas Swaps 4Q-20 FY-21 FY-22 Wtd-avg price ($/MMBtu) ($0.82) ($0.55) ($0.53) HH Volume (MMBtu) 11,897,0001 42,522,500 Wtd-avg price ($/MMBtu) $2.65 $2.59 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 10-30-20 17 Natural gas liquids consist of Mt. Belvieu purity ethane and Mt. Belvieu non-TET propane, normal butane, isobutane, and natural gasoline
YE-19 Base Production Decline Expectations 100 Total Production Decline 80 86.5 60 60.8 40 49.8 MBOE/d 42.4 37.1 20 33.2 0 Dec-19 Dec-20 Dec-21 Dec-22 Dec-23 Dec-24 30 Oil Production Decline 25 27.5 20 15 15.4 MBO/d 10 11.7 9.6 5 8.2 7.2 0 Dec-19 Dec-20 Dec-21 Dec-22 Dec-23 Dec-24 18
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) 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 19 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) 12/31/19 3/31/201 6/30/20 9/30/20 Net Debt $1,194,742 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 20 1Reflects revised and restated figures in 1Q-20 10-Q/A
Supplemental Non-GAAP Financial Measures 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 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. 21
