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): May 4, 2022
(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 May 4, 2022, Laredo Petroleum, Inc. (the "Company") announced its financial and operating results for the quarter ended March 31, 2022. 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 May 5, 2022 at 7:30 am Central Time to discuss these results. To access the call, please dial 877.930.8286 or 253.336.8309 for international callers, and use conference code 1653949. A telephonic replay of the call will be available approximately two hours after the call through May 12, 2022 by dialing 855.859.2056, and using conference code 1653949. 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 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 be deemed incorporated by reference into any filing under the Securities Act of 1933, as amended (the "Securities Act"), or the Exchange Act.
Item 7.01. Regulation FD Disclosure.
On May 4, 2022, 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 May 4, 2022, 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 releases, teleconference and 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, 2021 and the Company's other filings 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 exhibits attached hereto are deemed to be "furnished" and shall not be deemed "filed" for the purpose of Section 18 of the Exchange Act, or otherwise subject to the liabilities of that section, nor shall such information be deemed incorporated by reference into any filing under the Securities Act or the Exchange Act.
Item 9.01. Financial Statements and Exhibits.
(d) Exhibits.
| Exhibit Number | Description | |||||||
| 104 | Cover Page Interactive Data File (formatted as Inline XBRL). | |||||||
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
| LAREDO PETROLEUM, INC. | ||||||||
Date: May 4, 2022 | 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 First-Quarter 2022 Financial and Operating Results
TULSA, OK - May 4, 2022 - Laredo Petroleum, Inc. (NYSE: LPI) ("Laredo" or the "Company") today announced its first-quarter 2022 financial and operating results. A conference call and webcast to discuss the results is planned for 7:30 a.m. CT, Thursday, May 5, 2022. Complete details can be found within this release.
First-Quarter 2022 Highlights
•Reported a net loss of $86.8 million and cash flows from operating activities of $170.9 million, generating Adjusted EBITDA1 of $222.1 million and Free Cash Flow1 of $23.2 million
•Reduced Net Debt1/Consolidated EBITDAX1 ratio to 1.9x
•Produced 40,295 barrels of oil per day ("BOPD") and 85,118 barrels of oil equivalent per day ("BOEPD"), in line with guidance and an increase of 66% and 8%, respectively, versus first-quarter 2021
•Incurred capital expenditures of $171 million, excluding non-budgeted acquisitions and leasehold expenditures, in line with guidance
Subsequent Highlights
•Secured pricing and supply for majority of second-half 2022 expenditures, increasing 2022 capital budget by 6% to ~$550 million
•Increased the borrowing base and elected commitment of the Company's senior secured credit facility to $1.25 billion and $1.0 billion, respectively
•Achieved Project Canary2 TrustWellTM Gold certification for approximately 31,500 BOEPD of gross operated production to become the first Permian producer to receive TrustWellTM certified responsibly sourced oil and natural gas production
"We have executed extremely well year-to-date, generating Free Cash Flow and further reducing our leverage ratio," commented Jason Pigott, President and Chief Executive Officer. "Well performance from Howard and western Glasscock counties is driving our strong oil production and capital efficiency. The exceptional returns of our development program in the current commodity environment enabled Free Cash Flow generation in the quarter."
"Free Cash Flow during 2022 is still expected to exceed $300 million, despite the highly inflationary environment" continued Mr. Pigott. "We plan to utilize the majority of our free cash this year to reduce debt by $300 million and expect to achieve our leverage targets of 1.5x in the third quarter of 2022 and 1.0x by the first quarter of 2023. As we reduce our leverage ratio, absolute debt levels and interest expense, we anticipate that we will be in a position to institute measures to return cash to shareholders by early 2023."
First-Quarter 2022 Financial Results
For the first quarter of 2022, the Company reported a net loss attributable to common stockholders of $86.8 million, or $5.18 per diluted share, which included a non-cash loss on derivatives, net, of $200.4 million, or $11.95 per diluted share. Adjusted Net Income1 for the first quarter of 2022 was $88.2 million, or $5.17 per adjusted diluted share. Adjusted EBITDA for the first quarter of 2022 was $222.1 million.
1Non-GAAP financial measure; please see supplemental reconciliations of GAAP to non-GAAP financial measures at the end of this release.
2Project Canary is a data analytics and environmental assessment company that Laredo has partnered with to provide industry-specific certification for portions of Laredo's operations through Project Canary's TrustWellTM certification and installation of a continuous monitoring system.
Operations Summary
In the first quarter of 2022, the Company's total and oil production averaged 85,118 BOEPD and 40,295 BOPD, respectively. Both metrics were in-line with guidance, driven by solid execution and well performance, including results from wells in the Middle Spraberry and Wolfcamp D formations.
Lease operating expenses ("LOE") in first-quarter 2022 were $5.34 per BOE, higher than original guidance, reflecting inflation and integration costs from recently acquired assets. The increase is primarily related to artificial lift and flowback management on new wells in Howard and western Glasscock counties. This includes higher costs for generators and fuel to operate electric submersible pumps on wells in Howard County and higher compression and fuel gas costs for gas lifted wells in western Glasscock County.
Laredo is working to offset these cost pressures by reallocating power generation systems to high-line power as it becomes available in its operating areas, switching to liquefied natural gas generator systems and consolidating production in Howard County to upgraded, Laredo-built facilities. The Company anticipates these cost pressures will persist for the remainder of 2022 and expects total LOE will be consistent with first quarter levels, with unit LOE varying with production levels.
During the first quarter of 2022, Laredo maintained its improved venting/flaring performance on its acquired properties in Howard County. The Company vented/flared 0.64% of produced gas during first-quarter 2022, roughly flat compared to the 0.61% vented/flared in the fourth quarter of 2021.
In the first quarter of 2022, the Company completed and TIL'd 18 wells. Laredo released one drilling rig and one completions crew during the quarter. The Company is currently operating two drilling rigs and one completions crew and expects to complete 11 wells and TIL seven wells during the second quarter of 2022.
First-Quarter 2022 Incurred Capital Expenditures
During the first quarter of 2022, total incurred capital expenditures were $171 million, excluding non-budgeted acquisitions and leasehold expenditures. Total investments included $146 million in drilling and completions activities, including $4 million of non-operated capital, $5 million in land, exploration and data related costs, $13
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million in infrastructure, including Laredo Midstream Services investments, and $7 million in other capitalized costs. Non-budgeted acquisitions and leasehold expenditures were $8 million.
2022 Capital Investment Outlook
Laredo is working to mitigate the impact of inflationary and supply chain pressures impacting both the energy industry and global economy. The Company's initial capital budget anticipated approximately 15% inflation, with a significant portion of required goods and services contracted through the first half of 2022. Although first-quarter 2022 capital expenditures were in-line with the Company's guidance of $170 million, the price increases are impacting Laredo's full-year outlook.
The Company recently contracted the majority of its services related to its capital program for the second half of 2022 and now has pricing and supply secured for approximately 85% of its required goods and services for the remainder of 2022. Incorporating inflation to date and the price increases associated with contracted second-half pricing, the Company adjusted its full-year 2022 capital budget to ~$550 million, up from ~$520 million.
Responsibly Sourced Gas/Oil Certification
In November 2021, Laredo further demonstrated its commitment to ESG leadership as the first operator in the Permian Basin to seek TrustWellTM certification for its responsibly sourced oil and natural gas production. The third-party certification covers the Company's operating standards and practices for horizontal wells in its Howard and western Glasscock County development areas. After significant work demonstrating its sustainable operating practices, the Company has been awarded Gold certification for production from 73 horizontal wells in the certification area, representing approximately 31,500 BOEPD of its gross operated production. In addition to the recognition of its sustainable operating practices, the Company is uniquely positioned among Permian Basin operators to benefit as premium markets are developed for certified responsibly sourced natural gas and oil production.
Liquidity
At March 31, 2022, the Company had outstanding borrowings of $100 million on its $725 million senior secured credit facility, resulting in available capacity, after the reduction for outstanding letters of credit, of $581 million. Including cash and cash equivalents of $65 million, total liquidity was $646 million.
On April 13, 2022, as part of the semi-annual borrowing base redetermination, the Company's borrowing base was increased to $1.25 billion from $1.0 billion and the elected commitment was increased to $1.0 billion from $725 million. At May 3, 2022, the Company had outstanding borrowings of $50 million, resulting in available capacity, after the reduction for outstanding letters of credit, of $906 million. Including cash and cash equivalents of $104 million, total liquidity was $1.01 billion.
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Second-Quarter and Full-Year 2022 Guidance
The table below reflects the Company's guidance for total and oil production and incurred capital expenditures for second-quarter and full-year 2022.
| 2Q-22E | FY-22E | |||||||||||||
| Total production (MBOE per day) | 85.0 - 88.0 | 82.0 - 86.0 | ||||||||||||
| Oil production (MBOPD) | 40.0 - 42.0 | 39.5 - 42.5 | ||||||||||||
| Incurred capital expenditures, excluding non-budgeted acquisitions ($ MM) | ~$125 | ~$550 | ||||||||||||
The table below reflects the Company's guidance for select revenue and expense items for the second quarter of 2022.
| 2Q-22E | ||||||||
| Average sales price realizations (excluding derivatives): | ||||||||
| Oil (% of WTI) | 100% | |||||||
| NGL (% of WTI) | 34% | |||||||
| Natural gas (% of Henry Hub) | 68% | |||||||
| Net settlements received (paid) for matured commodity derivatives ($ MM): | ||||||||
| Oil | ($119) | |||||||
| NGL | ($16) | |||||||
| Natural gas | ($20) | |||||||
| Other ($ MM): | ||||||||
| Net income (expense) of purchased oil | $0 | |||||||
| Selected average costs & expenses: | ||||||||
| Lease operating expenses ($/BOE) | $5.35 | |||||||
| Production and ad valorem taxes (% of oil, NGL and natural gas sales revenues) | 6.50% | |||||||
| Transportation and marketing expenses ($/BOE) | $1.65 | |||||||
| General and administrative expenses (excluding LTIP, $/BOE) | $1.65 | |||||||
| General and administrative expenses (LTIP cash, $/BOE) | $0.45 | |||||||
| General and administrative expenses (LTIP non-cash, $/BOE) | $0.25 | |||||||
| Depletion, depreciation and amortization ($/BOE) | $9.75 | |||||||
Conference Call Details
On Thursday, May 5, 2022, at 7:30 a.m. CT, Laredo will host a conference call to discuss its first-quarter 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 1653949, 10 minutes prior to the scheduled conference time. A telephonic replay will be available two hours after the call through Thursday, May 12, 2022. Participants may access this replay by dialing 855.859.2056, using conference code 1653949.
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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.
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. Such statements are not guarantees of future performance and involve risks, assumptions and uncertainties.
General risks relating to Laredo include, but are not limited to, the decline in prices of oil, natural gas liquids and natural gas and the related impact to financial statements as a result of asset impairments and revisions to reserve estimates, the ability of the Company to execute its strategies, including its ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to its financial results and to successfully integrate acquired businesses, assets and properties, oil production quotas or other actions that might be imposed by the Organization of Petroleum Exporting Countries and other producing countries ("OPEC+"), the outbreak of disease, such as the coronavirus ("COVID-19") pandemic, and any related government policies and actions, changes in domestic and global production, supply and demand for commodities, including as a result of the COVID-19 pandemic, actions by OPEC+ and the Russian-Ukrainian military conflict, long-term performance of wells, drilling and operating risks, the increase in service and supply costs, including as a result of inflationary pressures, tariffs on steel, pipeline transportation and storage constraints in the Permian Basin, the possibility of production curtailment, hedging activities, the impacts of severe weather, including the freezing of wells and pipelines in the Permian Basin due to cold weather, possible impacts of litigation and regulations, the impact of the Company's transactions, if any, with its securities from time to time, the impact of new laws and regulations, including those regarding the use of hydraulic fracturing, the impact of new environmental, health and safety requirements applicable to the Company's business activities, the possibility of the elimination of federal income tax deductions for oil and gas exploration and development and other factors, including those and other risks described in its Annual Report on Form 10-K for the year ended December 31, 2021 and those set forth from time to time in other filings with the Securities and Exchange Commission ("SEC"). These documents are available through Laredo's website at www.laredopetro.com under the tab "Investor Relations" or through the SEC's Electronic Data Gathering and Analysis Retrieval System at www.sec.gov. Any of these factors could cause Laredo's actual results and plans to differ materially from those in the forward-looking statements. Therefore, Laredo can give no assurance that its future results will be as estimated. Any forward-looking statement speaks only as of the date on which such statement is made. Laredo does not intend to, and disclaims any obligation to, correct, update or revise any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.
The SEC generally permits oil and natural gas companies, in filings made with the SEC, to disclose proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, and certain probable and possible reserves that meet the SEC's definitions for such terms. In this 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
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section potentially supporting numerous drilling locations, which, when compared to a conventional play, typically has a lower geological and/or commercial development risk. "EURs" are based on the Company’s previous operating experience in a given area and publicly available information relating to the operations of producers who are conducting operations in these areas. Unbooked resource potential and "EURs" do not constitute reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or SEC rules and do not include any proved reserves. Actual quantities of reserves that may be ultimately recovered from the Company’s interests may differ substantially from those presented herein. Factors affecting ultimate recovery include the scope of the Company’s ongoing drilling program, which will be directly affected by the availability of capital, decreases in oil, natural gas liquids and natural gas prices, well spacing, drilling and production costs, availability and cost of drilling services and equipment, lease expirations, transportation constraints, regulatory approvals, negative revisions to reserve estimates and other factors, as well as actual drilling results, including geological and mechanical factors affecting recovery rates. "EURs" from reserves may change significantly as development of the Company’s core assets provides additional data. In addition, the Company's production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases. "Type curve" refers to a production profile of a well, or a particular category of wells, for a specific play and/or area. The "standardized measure" of discounted future new cash flows is calculated in accordance with SEC regulations and a discount rate of 10%. Actual results may vary considerably and should not be considered to represent the fair market value of the Company’s proved reserves.
This press release and any accompanying disclosures include financial measures that are not in accordance with generally accepted accounting principles ("GAAP"), such as Adjusted EBITDA, Adjusted Net Income 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.
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Laredo Petroleum, Inc.
Selected operating data
| Three months ended March 31, | ||||||||||||||
| 2022 | 2021 | |||||||||||||
| (unaudited) | ||||||||||||||
| Sales volumes: | ||||||||||||||
| Oil (MBbl) | 3,627 | 2,183 | ||||||||||||
| NGL (MBbl) | 1,994 | 2,321 | ||||||||||||
| Natural gas (MMcf) | 12,243 | 15,630 | ||||||||||||
Oil equivalents (MBOE)(1)(2) | 7,661 | 7,109 | ||||||||||||
Average daily oil equivalent sales volumes (BOE/D)(2) | 85,118 | 78,989 | ||||||||||||
Average daily oil sales volumes (Bbl/D)(2) | 40,295 | 24,261 | ||||||||||||
Average sales prices(2): | ||||||||||||||
Oil ($/Bbl)(3) | $ | 95.81 | $ | 58.48 | ||||||||||
NGL ($/Bbl)(3) | $ | 32.68 | $ | 17.96 | ||||||||||
Natural gas ($/Mcf)(3) | $ | 3.15 | $ | 2.12 | ||||||||||
Average sales price ($/BOE)(3) | $ | 58.90 | $ | 28.48 | ||||||||||
Oil, with commodity derivatives ($/Bbl)(4) | $ | 67.24 | $ | 45.03 | ||||||||||
NGL, with commodity derivatives ($/Bbl)(4) | $ | 26.04 | $ | 11.25 | ||||||||||
Natural gas, with commodity derivatives ($/Mcf)(4) | $ | 2.46 | $ | 1.66 | ||||||||||
Average sales price, with commodity derivatives ($/BOE)(4) | $ | 42.54 | $ | 21.15 | ||||||||||
Selected average costs and expenses per BOE sold(2): | ||||||||||||||
| Lease operating expenses | $ | 5.34 | $ | 2.66 | ||||||||||
| Production and ad valorem taxes | 3.59 | 1.87 | ||||||||||||
| Transportation and marketing expenses | 1.92 | 1.71 | ||||||||||||
| Midstream service expenses | 0.18 | 0.12 | ||||||||||||
| General and administrative (excluding LTIP) | 1.75 | 1.36 | ||||||||||||
| Total selected operating expenses | $ | 12.78 | $ | 7.72 | ||||||||||
| General and administrative (LTIP): | ||||||||||||||
| LTIP cash | $ | 0.85 | $ | 0.23 | ||||||||||
| LTIP non-cash | $ | 0.27 | $ | 0.26 | ||||||||||
| Depletion, depreciation and amortization | $ | 9.59 | $ | 5.36 | ||||||||||
(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.
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Laredo Petroleum, Inc.
Consolidated balance sheets
| (in thousands, except share data) | March 31, 2022 | December 31, 2021 | ||||||||||||
| (unaudited) | ||||||||||||||
| Assets | ||||||||||||||
| Current assets: | ||||||||||||||
| Cash and cash equivalents | $ | 65,137 | $ | 56,798 | ||||||||||
| Accounts receivable, net | 213,549 | 151,807 | ||||||||||||
| Derivatives | 5,899 | 4,346 | ||||||||||||
| Other current assets | 17,767 | 22,906 | ||||||||||||
| Total current assets | 302,352 | 235,857 | ||||||||||||
| Property and equipment: | ||||||||||||||
| Oil and natural gas properties, full cost method: | ||||||||||||||
| Evaluated properties | 9,149,982 | 8,968,668 | ||||||||||||
| Unevaluated properties not being depleted | 156,899 | 170,033 | ||||||||||||
| Less: accumulated depletion and impairment | (7,089,265) | (7,019,670) | ||||||||||||
| Oil and natural gas properties, net | 2,217,616 | 2,119,031 | ||||||||||||
| Midstream service assets, net | 94,632 | 96,528 | ||||||||||||
| Other fixed assets, net | 35,374 | 34,590 | ||||||||||||
| Property and equipment, net | 2,347,622 | 2,250,149 | ||||||||||||
| Derivatives | 33,862 | 32,963 | ||||||||||||
| Other noncurrent assets, net | 42,494 | 32,855 | ||||||||||||
| Total assets | $ | 2,726,330 | $ | 2,551,824 | ||||||||||
| Liabilities and stockholders' equity | ||||||||||||||
| Current liabilities: | ||||||||||||||
| Accounts payable and accrued liabilities | $ | 73,228 | $ | 71,386 | ||||||||||
| Accrued capital expenditures | 69,018 | 50,585 | ||||||||||||
| Undistributed revenue and royalties | 162,233 | 117,920 | ||||||||||||
| Derivatives | 365,256 | 179,809 | ||||||||||||
| Other current liabilities | 105,767 | 107,213 | ||||||||||||
| Total current liabilities | 775,502 | 526,913 | ||||||||||||
| Long-term debt, net | 1,421,821 | 1,425,858 | ||||||||||||
| Derivatives | 17,450 | — | ||||||||||||
| Asset retirement obligations | 69,677 | 69,057 | ||||||||||||
| Other noncurrent liabilities | 18,092 | 16,216 | ||||||||||||
| Total liabilities | 2,302,542 | 2,038,044 | ||||||||||||
| Commitments and contingencies | ||||||||||||||
| Stockholders' equity: | ||||||||||||||
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued as of March 31, 2022 and December 31, 2021 | — | — | ||||||||||||
Common stock, $0.01 par value, 22,500,000 shares authorized and 17,302,320 and 17,074,516 issued and outstanding as of March 31, 2022 and December 31, 2021, respectively | 173 | 171 | ||||||||||||
| Additional paid-in capital | 2,785,415 | 2,788,628 | ||||||||||||
| Accumulated deficit | (2,361,800) | (2,275,019) | ||||||||||||
| Total stockholders' equity | 423,788 | 513,780 | ||||||||||||
| Total liabilities and stockholders' equity | $ | 2,726,330 | $ | 2,551,824 | ||||||||||
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Laredo Petroleum, Inc.
Consolidated statements of operations
| Three months ended March 31, | ||||||||||||||
| (in thousands, except per share data) | 2022 | 2021 | ||||||||||||
| (unaudited) | ||||||||||||||
| Revenues: | ||||||||||||||
| Oil sales | $ | 347,443 | $ | 127,701 | ||||||||||
| NGL sales | 65,155 | 41,678 | ||||||||||||
| Natural gas sales | 38,589 | 33,078 | ||||||||||||
| Midstream service revenues | 2,344 | 1,296 | ||||||||||||
| Sales of purchased oil | 78,864 | 46,477 | ||||||||||||
| Total revenues | 532,395 | 250,230 | ||||||||||||
| Costs and expenses: | ||||||||||||||
| Lease operating expenses | 40,876 | 18,918 | ||||||||||||
| Production and ad valorem taxes | 27,487 | 13,283 | ||||||||||||
| Transportation and marketing expenses | 14,743 | 12,127 | ||||||||||||
| Midstream service expenses | 1,414 | 858 | ||||||||||||
| Costs of purchased oil | 82,964 | 49,916 | ||||||||||||
| General and administrative | 21,944 | 13,073 | ||||||||||||
| Depletion, depreciation and amortization | 73,492 | 38,109 | ||||||||||||
| Other operating expenses | 1,019 | 1,143 | ||||||||||||
| Total costs and expenses | 263,939 | 147,427 | ||||||||||||
| Operating income | 268,456 | 102,803 | ||||||||||||
| Non-operating income (expense): | ||||||||||||||
| Loss on derivatives, net | (325,816) | (154,365) | ||||||||||||
| Interest expense | (32,477) | (25,946) | ||||||||||||
| Loss on disposal of assets, net | (260) | (72) | ||||||||||||
| Other income, net | 2,439 | 1,379 | ||||||||||||
| Total non-operating expense, net | (356,114) | (179,004) | ||||||||||||
| Loss before income taxes | (87,658) | (76,201) | ||||||||||||
| Income tax (expense) benefit: | ||||||||||||||
| Current | (1,218) | — | ||||||||||||
| Deferred | 2,095 | 762 | ||||||||||||
| Total income tax benefit | 877 | 762 | ||||||||||||
| Net loss | $ | (86,781) | $ | (75,439) | ||||||||||
| Net loss per common share: | ||||||||||||||
| Basic | $ | (5.18) | $ | (6.33) | ||||||||||
| Diluted | $ | (5.18) | $ | (6.33) | ||||||||||
| Weighted-average common shares outstanding: | ||||||||||||||
| Basic | 16,767 | 11,918 | ||||||||||||
| Diluted | 16,767 | 11,918 | ||||||||||||
9
Laredo Petroleum, Inc.
Consolidated statements of cash flows
| Three months ended March 31, | ||||||||||||||
| (in thousands) | 2022 | 2021 | ||||||||||||
| (unaudited) | ||||||||||||||
| Cash flows from operating activities: | ||||||||||||||
Net loss | $ | (86,781) | $ | (75,439) | ||||||||||
Adjustments to reconcile net loss to net cash provided by operating activities: | ||||||||||||||
| Share-settled equity-based compensation, net | 2,053 | 2,068 | ||||||||||||
| Depletion, depreciation and amortization | 73,492 | 38,109 | ||||||||||||
| Mark-to-market on derivatives: | ||||||||||||||
| Loss on derivatives, net | 325,816 | 154,365 | ||||||||||||
| Settlements paid for matured derivatives, net | (125,370) | (41,174) | ||||||||||||
| Premiums received for commodity derivatives | — | 9,041 | ||||||||||||
| Amortization of debt issuance costs | 1,541 | 989 | ||||||||||||
| Amortization of operating lease right-of-use assets | 5,025 | 2,997 | ||||||||||||
| Deferred income tax benefit | (2,095) | (762) | ||||||||||||
| Other, net | 425 | 1,491 | ||||||||||||
| Changes in operating assets and liabilities: | ||||||||||||||
| Accounts receivable, net | (61,742) | (3,728) | ||||||||||||
| Other current assets | 5,092 | (10,264) | ||||||||||||
| Other noncurrent assets, net | (15,227) | (1,636) | ||||||||||||
| Accounts payable and accrued liabilities | 1,842 | 9,065 | ||||||||||||
| Undistributed revenue and royalties | 44,294 | 7,290 | ||||||||||||
| Other current liabilities | (1,471) | (19,622) | ||||||||||||
| Other noncurrent liabilities | 3,988 | (1,639) | ||||||||||||
| Net cash provided by operating activities | 170,882 | 71,151 | ||||||||||||
| Cash flows from investing activities: | ||||||||||||||
| Acquisitions of oil and natural gas properties, net | (7,870) | — | ||||||||||||
| Capital expenditures: | ||||||||||||||
| Oil and natural gas properties | (143,500) | (68,329) | ||||||||||||
| Midstream service assets | (293) | (329) | ||||||||||||
| Other fixed assets | (2,052) | (551) | ||||||||||||
| Proceeds from dispositions of capital assets, net of selling costs | 2,019 | 189 | ||||||||||||
| Net cash used in investing activities | (151,696) | (69,020) | ||||||||||||
| Cash flows from financing activities: | ||||||||||||||
| Borrowings on Senior Secured Credit Facility | 50,000 | 15,000 | ||||||||||||
| Payments on Senior Secured Credit Facility | (55,000) | (50,000) | ||||||||||||
| Proceeds from issuance of common stock, net of offering costs | — | 26,866 | ||||||||||||
| Stock exchanged for tax withholding | (5,847) | (1,290) | ||||||||||||
| Other | — | 2,798 | ||||||||||||
| Net cash used in financing activities | (10,847) | (6,626) | ||||||||||||
| Net increase (decrease) in cash and cash equivalents | 8,339 | (4,495) | ||||||||||||
| Cash and cash equivalents, beginning of period | 56,798 | 48,757 | ||||||||||||
| Cash and cash equivalents, end of period | $ | 65,137 | $ | 44,262 | ||||||||||
10
Laredo Petroleum, Inc.
Total incurred capital expenditures
The following table presents the components of the Company's incurred capital expenditures, excluding non-budgeted acquisition costs, for the periods presented:
| Three months ended March 31, | ||||||||||||||
| (in thousands) | 2022 | 2021 | ||||||||||||
| (unaudited) | ||||||||||||||
| Oil and natural gas properties | $ | 168,368 | $ | 68,449 | ||||||||||
| Midstream service assets | 459 | 876 | ||||||||||||
| Other fixed assets | 2,072 | 600 | ||||||||||||
| Total incurred capital expenditures, excluding non-budgeted acquisition costs | $ | 170,899 | $ | 69,925 | ||||||||||
11
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, Adjusted EBITDA, Consolidated EBITDAX, Net Debt and Net Debt to Consolidated EBITDAX, as defined by the Company, may not be comparable to similarly titled measures used by other companies. Furthermore, these non-GAAP financial measures should not be considered in isolation or as a substitute for GAAP measures of liquidity or financial performance, but rather should be considered in conjunction with GAAP measures, such as net income or loss, operating income or loss or cash flows from operating activities.
Free Cash Flow (Unaudited)
Free Cash Flow is a non-GAAP financial measure that the Company defines as net cash provided by operating activities (GAAP) before changes in operating assets and liabilities, net, less incurred capital expenditures, excluding non-budgeted acquisition costs. Free Cash Flow does not represent funds available for future discretionary use because it excludes funds required for future debt service, capital expenditures, acquisitions, working capital, income taxes, franchise taxes and other commitments and obligations. However, management believes Free Cash Flow is useful to management and investors in evaluating operating trends in its business that are affected by production, commodity prices, operating costs and other related factors. There are significant limitations to the use of Free Cash Flow as a measure of performance, including the lack of comparability due to the different methods of calculating Free Cash Flow reported by different companies.
The following table presents a reconciliation of net cash provided by operating activities (GAAP) to Free Cash Flow (non-GAAP) for the periods presented:
| Three months ended March 31, | ||||||||||||||
| (in thousands) | 2022 | 2021 | ||||||||||||
| (unaudited) | ||||||||||||||
| Net cash provided by operating activities | $ | 170,882 | $ | 71,151 | ||||||||||
| Less: | ||||||||||||||
| Change in current assets and liabilities, net | (11,985) | (17,259) | ||||||||||||
| Change in noncurrent assets and liabilities, net | (11,239) | (3,275) | ||||||||||||
| Cash flows from operating activities before changes in operating assets and liabilities, net | 194,106 | 91,685 | ||||||||||||
| Less incurred capital expenditures, excluding non-budgeted acquisition costs: | ||||||||||||||
Oil and natural gas properties(1) | 168,368 | 68,449 | ||||||||||||
Midstream service assets(1) | 459 | 876 | ||||||||||||
| Other fixed assets | 2,072 | 600 | ||||||||||||
| Total incurred capital expenditures, excluding non-budgeted acquisition costs | 170,899 | 69,925 | ||||||||||||
| Free Cash Flow (non-GAAP) | $ | 23,207 | $ | 21,760 | ||||||||||
_____________________________________________________________________________
(1)Includes capitalized share-settled equity-based compensation and asset retirement costs.
12
Adjusted Net Income (Unaudited)
Adjusted Net Income is a non-GAAP financial measure that the Company defines as net income or loss (GAAP) plus adjustments for mark-to-market on derivatives, premiums paid or received for commodity derivatives that matured during the period, impairment expense, gains or losses on disposal of assets, income taxes, other non-recurring income and expenses and adjusted income tax expense. Management 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 net loss (GAAP) to Adjusted Net Income (non-GAAP) for the periods presented:
| Three months ended March 31, | ||||||||||||||
| (in thousands, except per share data) | 2022 | 2021 | ||||||||||||
| (unaudited) | ||||||||||||||
Net loss | $ | (86,781) | $ | (75,439) | ||||||||||
| Plus: | ||||||||||||||
| Mark-to-market on derivatives: | ||||||||||||||
| Loss on derivatives, net | 325,816 | 154,365 | ||||||||||||
Settlements paid for matured derivatives, net | (125,370) | (41,174) | ||||||||||||
Net premiums paid for commodity derivatives that matured during the period(1) | — | (11,005) | ||||||||||||
| Loss on disposal of assets, net | 260 | 72 | ||||||||||||
| Income tax benefit | (877) | (762) | ||||||||||||
| Adjusted income before adjusted income tax expense | 113,048 | 26,057 | ||||||||||||
Adjusted income tax expense(2) | (24,871) | (5,733) | ||||||||||||
| Adjusted Net Income (non-GAAP) | $ | 88,177 | $ | 20,324 | ||||||||||
| Net loss per common share: | ||||||||||||||
| Basic | $ | (5.18) | $ | (6.33) | ||||||||||
| Diluted | $ | (5.18) | $ | (6.33) | ||||||||||
| Adjusted Net Income per common share: | ||||||||||||||
| Basic | $ | 5.26 | $ | 1.71 | ||||||||||
| Diluted | $ | 5.26 | $ | 1.71 | ||||||||||
| Adjusted diluted | $ | 5.17 | $ | 1.69 | ||||||||||
| Weighted-average common shares outstanding: | ||||||||||||||
| Basic | 16,767 | 11,918 | ||||||||||||
| Diluted | 16,767 | 11,918 | ||||||||||||
| Adjusted diluted | 17,040 | 12,040 | ||||||||||||
_______________________________________________________________________________
(1)Reflects net premiums paid previously or upon settlement that are attributable to derivatives settled in the respective periods presented.
(2)Adjusted income tax expense is calculated by applying a statutory tax rate of 22% for each of the periods ended March 31, 2022 and 2021.
13
Adjusted EBITDA (Unaudited)
Adjusted EBITDA is a non-GAAP financial measure that the Company defines as net income or loss (GAAP) plus adjustments for share-settled equity-based compensation, depletion, depreciation and amortization, impairment expense, mark-to-market on derivatives, premiums paid or received 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 March 31, | ||||||||||||||
| (in thousands) | 2022 | 2021 | ||||||||||||
| (unaudited) | ||||||||||||||
| Net loss | $ | (86,781) | $ | (75,439) | ||||||||||
| Plus: | ||||||||||||||
| Share-settled equity-based compensation, net | 2,053 | 2,068 | ||||||||||||
| Depletion, depreciation and amortization | 73,492 | 38,109 | ||||||||||||
| Mark-to-market on derivatives: | ||||||||||||||
| Loss on derivatives, net | 325,816 | 154,365 | ||||||||||||
Settlements paid for matured derivatives, net | (125,370) | (41,174) | ||||||||||||
Net premiums paid for commodity derivatives that matured during the period(1) | — | (11,005) | ||||||||||||
| Accretion expense | 1,019 | 1,143 | ||||||||||||
| Loss on disposal of assets, net | 260 | 72 | ||||||||||||
| Interest expense | 32,477 | 25,946 | ||||||||||||
| Income tax benefit | (877) | (762) | ||||||||||||
| Adjusted EBITDA (non-GAAP) | $ | 222,089 | $ | 93,323 | ||||||||||
_____________________________________________________________________________
(1)Reflects net premiums paid previously or upon settlement that are attributable to derivatives settled in the respective periods presented.
14
Consolidated EBITDAX (Unaudited)
Consolidated EBITDAX is a non-GAAP financial measure defined in the Company's Senior Secured Credit Facility as net income or loss (GAAP) plus adjustments for extraordinary gains (or losses), non-cash recurring gains (or losses), depletion, depreciation and amortization expense, interest expense, any provisions for (or benefit from) income or franchise taxes, exploration expenses and other non-cash charges. Consolidated EBITDAX is used by the Company’s management for various purposes, including as a measure of operating performance and compliance under the Company's Senior Secured Credit Facility. Additional information on the calculation of Consolidated EBITDAX can be found in the Company's Eighth Amendment to the Senior Secured Credit Facility as filed with the SEC on April 19, 2022.
The following table presents a reconciliation of net income (loss) (GAAP) to Consolidated EBITDAX (non-GAAP) for the periods presented:
| Three months ended | ||||||||||||||||||||
| (in thousands) | March 31, 2022 | December 31, 2021 | September 30, 2021 | |||||||||||||||||
| (unaudited) | ||||||||||||||||||||
| Net income (loss) | $ | (86,781) | $ | 216,276 | $ | 136,832 | ||||||||||||||
| Plus: | ||||||||||||||||||||
| Share-settled equity-based compensation, net | 2,053 | 2,066 | 1,811 | |||||||||||||||||
| Depletion, depreciation and amortization | 73,492 | 74,592 | 62,678 | |||||||||||||||||
| Mark-to-market on derivatives: | ||||||||||||||||||||
| (Gain) loss on derivatives, net | 325,816 | (15,372) | 96,240 | |||||||||||||||||
| Settlements paid for matured derivatives, net | (125,370) | (129,361) | (92,726) | |||||||||||||||||
| Accretion expense | 1,019 | 1,026 | 906 | |||||||||||||||||
| Gain on sale of oil and natural gas properties, net | — | — | (95,223) | |||||||||||||||||
| Loss on disposal of assets, net | 260 | 8,903 | 22 | |||||||||||||||||
| Interest expense | 32,477 | 31,163 | 30,406 | |||||||||||||||||
| Income tax (benefit) expense | (877) | 3,052 | 2,677 | |||||||||||||||||
| Consolidated EBITDAX (non-GAAP) | $ | 222,089 | $ | 192,345 | $ | 143,623 | ||||||||||||||
Net Debt (Unaudited)
Net Debt, a non-GAAP financial measure, is calculated as the face value of long-term debt plus any outstanding letters of credit, less cash and cash equivalents. Management believes Net Debt is useful to management and investors in determining the Company's leverage position since the Company has the ability, and may decide, to use a portion of its cash and cash equivalents to reduce debt. Net Debt as of March 31, 2022 $1.418 billion.
Net Debt to Consolidated EBITDAX (Unaudited)
Net Debt to Consolidated EBITDAX, a non-GAAP financial measure, is calculated as Net Debt, including letters of credit, divided by Consolidated EBITDAX, as defined in the Company's Senior Secured Credit Facility. For the purposes of calculating Consolidated EBITDAX for the period ended March 31, 2022, the calculation is the annualization of the three quarters ended March 31, 2022. Net Debt to Consolidated EBITDAX is used by the Company’s management for various purposes, including as a measure of operating performance, in presentations to its board of directors and as a basis for strategic planning and forecasting.
# # #
Investor Contact:
Ron Hagood
918.858.5504
rhagood@laredopetro.com
15
1Q-22 Earnings Presentation EXHIBIT 99.2
This presentation, including any oral statements made regarding the contents of this presentation, contains forward-looking statements as defined under Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, that address activities that Laredo Petroleum, Inc. (together with its subsidiaries, the “Company”, “Laredo” or “LPI”) assumes, plans, expects, believes, intends, projects, indicates, enables, transforms, estimates or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. The forward- looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. Such statements are not guarantees of future performance and involve risks, assumptions and uncertainties. General risks relating to Laredo include, but are not limited to, the decline in prices of oil, natural gas liquids and natural gas and the related impact to financial statements as a result of asset impairments and revisions to reserve estimates, the ability of the Company to execute its strategies, including its ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to its financial results and to successfully integrate acquired businesses, assets and properties, oil production quotas or other actions that might be imposed by the Organization of Petroleum Exporting Countries and other producing countries (“OPEC+”), the outbreak of disease, such as the coronavirus (“COVID-19”) pandemic, and any related government policies and actions, changes in domestic and global production, supply and demand for commodities, including as a result of the COVID-19 pandemic, actions by OPEC+ and the Russian-Ukrainian military conflict, long-term performance of wells, drilling and operating risks, the increase in service and supply costs, including as a result of inflationary pressures, tariffs on steel, pipeline transportation and storage constraints in the Permian Basin, the possibility of production curtailment, hedging activities, the impacts of severe weather, including the freezing of wells and pipelines in the Permian Basin due to cold weather, possible impacts of litigation and regulations, the impact of the Company’s transactions, if any, with its securities from time to time, the impact of new laws and regulations, including those regarding the use of hydraulic fracturing, the impact of new environmental, health and safety requirements applicable to the Company’s business activities, the possibility of the elimination of federal income tax deductions for oil and gas exploration and development and other factors, including those and other risks described in its Annual Report on Form 10-K for the year ended December 31, 2021, and those set forth from time to time in other filings with the Securities and Exchange Commission (“SEC”). These documents are available through Laredo’s website at www.laredopetro.com under the tab “Investor Relations” or through the SEC’s Electronic Data Gathering and Analysis Retrieval System at www.sec.gov. Any of these factors could cause Laredo’s actual results and plans to differ materially from those in the forward-looking statements. Therefore, Laredo can give no assurance that its future results will be as estimated. Any forward-looking statement speaks only as of the date on which such statement is made. Laredo does not intend to, and disclaims any obligation to, correct, update or revise any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. The SEC generally permits oil and natural gas companies, in filings made with the SEC, to disclose proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, and certain probable and possible reserves that meet the SEC’s definitions for such terms. In this presentation, the Company may use the terms “resource potential,” “resource play,” “estimated ultimate recovery,” or “EURs,” “type curve” and “standardized measure,” each of which the SEC guidelines restrict from being included in filings with the SEC without strict compliance with SEC definitions. These terms refer to the Company’s internal estimates of unbooked hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques. “Resource potential” is used by the Company to refer to the estimated quantities of hydrocarbons that may be added to proved reserves, largely from a specified resource play potentially supporting numerous drilling locations. A “resource play” is a term used by the Company to describe an accumulation of hydrocarbons known to exist over a large areal expanse and/or thick vertical section potentially supporting numerous drilling locations, which, when compared to a conventional play, typically has a lower geological and/or commercial development risk. “EURs” are based on the Company’s previous operating experience in a given area and publicly available information relating to the operations of producers who are conducting operations in these areas. Unbooked resource potential and “EURs” do not constitute reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or SEC rules and do not include any proved reserves. Actual quantities of reserves that may be ultimately recovered from the Company’s interests may differ substantially from those presented herein. Factors affecting ultimate recovery include the scope of the Company’s ongoing drilling program, which will be directly affected by the availability of capital, decreases in oil, natural gas liquids and natural gas prices, well spacing, drilling and production costs, availability and cost of drilling services and equipment, lease expirations, transportation constraints, regulatory approvals, negative revisions to reserve estimates and other factors, as well as actual drilling results, including geological and mechanical factors affecting recovery rates. “EURs” from reserves may change significantly as development of the Company’s core assets provides additional data. In addition, the Company’s production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases. “Type curve” refers to a production profile of a well, or a particular category of wells, for a specific play and/or area. The “standardized measure” of discounted future new cash flows is calculated in accordance with SEC regulations and a discount rate of 10%. Actual results may vary considerably and should not be considered to represent the fair market value of the Company’s proved reserves. This presentation includes financial measures that are not in accordance with generally accepted accounting principles (“GAAP”), such as Consolidated EBITDAX and Free Cash Flow. While management believes that such measures are useful for investors, they should not be used as a replacement for financial measures that are in accordance with GAAP. For definitions of such non-GAAP financial measures, please see the Appendix. Unless otherwise specified, references to “average sales price” refer to average sales price excluding the effects of the Company’s derivative transactions. All amounts, dollars and percentages presented in this presentation are rounded and therefore approximate. 2 Forward-Looking / Cautionary Statements
Optimize Capital Structure Targeting leverage of <1.5x by 3Q-22 and <1.0x by 1Q-23 Utilize FCF4 to reduce debt by ~$300 million in 2022 Maintain strong liquidity profile Improve cost of capital Return of capital to shareholders YE-21 Reserves 319 MMBOE (~38% Oil) $3.7B PV-103 Enterprise Value Market Capitalization1 $2.5 Billion $1.2 Billion (17.3mm Shares) Laredo Petroleum (NYSE: LPI) | Pure-Play Permian Energy Producer 1As of market close 3/29/2022; 2Assumes current activity pace; 3Assumes SEC pricing of $63 WTI oil & $3.35 HH gas 4See Appendix for definitions of non-GAAP financial measures Acreage FootprintCompany Snapshot Corporate Principles Driving Shareholder Value Net Acres | Years of Inventory2 ~166,000 ~8 Years Q1-22A Production 85.1 MBOE/D ~47% Oil Net Debt to Consolidated EBITDAX4 2.1x <1.5x YE-21A 3Q-22E Scope 1 Emissions mtCO2e/MBOE 17.5 12.5 2020A 2025 Target Leasehold Acreage Glasscock Howard Reagan Martin Midland Upton Sterling Irion Mitchell Dawson Borden TX Maximize Free Cash Flow4 High grade development to maximize capital efficiency Commodity mix improvement Focus on efficiencies and low-cost operations Disciplined hedge program Build scale through accretive transactions Advance Sustainability Formalized Board of Directors ESG oversight Meaningful emissions reduction targets Pay linked to performance ESG reporting aligned to industry- standard frameworks Diversity transparency via EEO-1 data disclosure 3
$1.2 Equity $1.5 Equity $1.3 Debt $1.0 Debt Current ProForma 2.7x 2.1x ≤1.5x YE-20A YE-21A 3Q-22E 31% 39% ~49% FY-20A FY-21A FY-22E 1See Appendix for definitions of non-GAAP financial measures; 2Assumes WTI oil price of $97 and HH gas price of $6.55; 3Based on 17.3 million shares outstanding Strong Value Creation Built on Disciplined Strategy 4 RETURN OF CAPITAL TO SHAREHOLDERS DISCIPLINED EXECUTION OF STRATEGY UNDERPINS VALUE CREATION FREE CASH FLOW1 EXPANSION 2019 - 2021 2022 2023+ GREW INVENTORY SHIFTED COMMODITY MIX REDUCED LEVERAGE FREE CASH FLOW1 GENERATION ACCELERATE LEVERAGE REDUCTION RETURN OF CAPITAL TO SHAREHOLDERS FREE CASH FLOW1 EXPANSION Acceleration of Value through Accretive Transactions MAINTENANCE CAPITAL Shifting Production Mix Improving Leverage Ratio1,2 Shifting Value to Shareholders through Debt Reduction Oil Production % of Total Production Net Debt-to-Consolidated EBITDAX Total Enterprise Value, $B$2.5B $2.5B $300 million of debt reduction Equal to ~$17 per share3
100 125 130 165 165 60 195 275 295 295 ≤$40 ≤$45 ≤$50 ≤$55 Inventory Upside Near-term Development Focus 1Gross operated location as of January 2022 (adjusted for 2021 completions) 2Locations may require the formation of drilling units to develop 3Flat oil price needed to achieve 10% IRR assuming gas price at 20:1 ratio Development Focus Areas ~460 ~320 ~1502 Avg. Breakeven Oil Price3 ~8 Years of Inventory1 Assumes: Current activity pace Low-risk, operated only Current development spacing <$55 breakeven oil price Howard Glasscock Howard W. Glasscock Eastern Reagan Midland Martin Sterling Mitchell ~160 Low Breakeven Oil Inventory Underpins Sustainable Free Cash Flow Generation 5 ~405 Howard W. Glasscock Eastern
0 25 50 75 100 125 150 175 200 0 90 180 270 360 C u m u la ti v e G ro s s O il P ro d u c ti o n p e r W e ll ( M B O ) Producing Days 0 20 40 60 80 100 120 0 30 60 90 120 150 C u m u la ti v e G ro s s O il P ro d u c ti o n p e r W e ll ( M B O ) Producing Days 1Gross operated location as of January 2022 (adjusted for 2021 completions); 2Production data normalized to 10,000’ lateral length, downtime days excluded Howard County Inventory and Well Performance Avg. LSS/WCA Well Performance2 Howard Borden North Howard Central Howard Middle Spraberry Performance2 Net Acres ~33,000 Q1-22A Net Production (MBOE/D) | % Oil 35.8 | 72% LSS / WCA Locations1 ~130 MS Locations1 ~35 Total Development Locations1 ~165 Avg. Lateral Length (ft.) ~11,500’ Avg. WI (%) ~92% Highlights 2022 development program entirely focused on Howard County Consolidated acreage position facilitates drilling of more capital efficient longer laterals Integrating eight Middle Spraberry wells into the 2022 development plan Thumper D 4MS Thumper B 2MS North Howard Central Howard (Wider-Spacing) Central Howard (Tighter-Spacing) Howard - Key Stats and Acreage Position 6
0 10 20 30 40 50 60 70 80 0 25 50 75 100 125 C u m u la ti v e G ro s s O il P ro d u c ti o n p e r W e ll ( M B O ) Producing Days 0 25 50 75 100 125 150 0 90 180 270 360 C u m u la ti v e G ro s s O il P ro d u c ti o n p e r W e ll ( M B O ) Producing Days Cook Package Books Package Glasscock Reagan W. Glasscock Eastern W. Glasscock County Inventory and Well Performance Avg. LSS/WCA/WCB Well Performance2 Wolfcamp D Performance2 Net Acres ~33,000 Q1-22A Net Production (MBOE/D) | % Oil 12.7 | 62% LSS / WCA / WCB Locations1 ~205 WCD Locations1 ~90 Total Development Locations1 ~295 Avg. Lateral Length (ft.) ~10,500’ Avg. WI (%) ~88% Highlights Completed a 10-well package in 4Q-21, including two Wolfcamp D appraisal wells Successful Wolfcamp D appraisal drilling unlocked ~90 locations, driven by optimized completion design 2024 development plan expected to focus on western Glasscock County Optimized Wolfcamp D Completion Design Historical Wolfcamp D Average W. Glasscock - Key Stats and Acreage Position 7 1Gross operated location as of January 2022 (adjusted for 2021 completions); 2Production data normalized to 10,000’ lateral length, downtime days excluded
~$910 ~$965 ~$1,025 ~$1,080 $80 $90 $100 $110 81% 8% 7% 4% 1,117 1,314 1,439 1,539 1,274 1,408 1,653 1,572 FY-19A FY-20A FY-21A YTD-22A Drilling Ft./Day/Rig Fractured Ft./Day/Crew 6 15 15 12 6 18 7 15 15 1Q-22A 2Q-22E 3Q-22E 4Q-22E N. Howard C. Howard Drilling & Completion Efficiencies Disciplined, Efficient Capital Program Maintains Prior Year Activity Levels 2022E Capital Program FY-22 Guidance Capital Expenditures ($MM) ~$550 Avg. Rig Count (Op) ~2.3 Avg. Frac Crews (Op) ~1.2 Spuds 65 Gross (62.9 Net) Completions 55 Gross (53.1 Net) Turn-in-Lines 55 Gross (53.1 Net) Production (MBOE/d) 82.0 – 86.0 Oil Production (MBO/d) 39.5 – 42.5 Capital Expenditures by Category DC&E (op) Facilities & Land Corporate DC&E (non-op) 8 Benchmark WTI Oil Price (per BBL) (Benchmark HH Gas Price assumes $6.55/mcf) 2022E Operated Turn-in-Line Well Count 2022E Consolidated EBITDAX1 Sensitivity - $MM 10,750' 9,950' 10,000' 11,800' FY-19A FY-20A FY-21A FY-22E FY-19A FY-20A FY-21A FY-22E Avg. Completed Lateral Length 1See Appendix for definitions of non-GAAP financial measures
~70% ~45% ~70% Natural Gas Natural Gas Liquids Crude Oil 2.7x 2.1x ≤1.5x ≤1.0x YE-20A YE-21A 3Q-22E 1Q-23E $578 $361 $400 $50 $44 $906 2022 2023 2024 2025 2026 2028 2029 1As of 5/3/2022; 2See Appendix for definitions of non-GAAP financial measures; 3Assumes WTI oil price of $97 and HH gas price of $6.55 for 2022 and WTI oil price of $85 and HH gas price of $5.15 for 2023; 4Calculated using guidance mid-point Free Cash Flow Supports Debt Reduction Net Debt to Consolidated EBITDAX2,3 Current Debt Maturity Profile1Q2-22E to Q4-22E Volumes Hedged4 Borrowing Base $1,250 MM Elected Commitment $1,000 MM Cash Balance $104 MM Liquidity ~$1,010 MM 9.500% Sr. Notes 2025 10.125% Sr. Notes 2028 7.750% Sr. Notes 2029 Drawn Credit Facility Outstanding Letters of Credit Undrawn Credit Facility 9 2022 Debt Reduction Target ~$300 million Current Liquidity1 ~$1.01 billion 3Q-22E Net Debt to Consolidated EBITDAX2,3 <1.5x Target 1Q-23E Net Debt to Consolidated EBITDAX2,3 <1.0x Target
1.95% 0.71% 0.37% 0.64% 0.78% FY-19A FY-20A FY-21A YTD-22A Zero routine flaring 10 <12.5 mtCO2e / MBOE <0.20% methane emissions1,2 18.08 17.54 12.50 2019 Baseline 2020 Performance Venting Reductions Flaring Reductions Pnuematics Reductions Combustion Reductions 2025 Target S c o p e 1 E m is s io n s m tC O 2 e / M B O E Defined Scope 1 Emissions Reduction Plan Systematic Plan to Achieve Emissions Reductions TrustWellTM Certification First Permian operator to receive TrustWellTM responsibly sourced certification Gold certification awarded for production from 73 horizontal wells representing ~31,500 BOEPD of gross operated production in the certification area Uniquely positioned among Permian Basin operators to benefit as premium markets are developed for certified responsibly sourced production Targets for 2025 12019 calendar year as baseline; 2As a percentage of natural gas production Percentage of Produced Natural Gas Flared / Vented Acquisitions Impact eu i
1Data as of 12/31/2021 Corporate and Community Responsibility Local and Impactful Philanthropy >$820,000 Total amount donated since 2019 to improve our local communities1 Diversity and Inclusion Efforts1 EEO-1 Data Disclosed in Company’s 2021 ESG & Climate Risk Report 27% 26% 61% 56% Women in Workforce Minorities in Workforce Women and/or Minorities in Professional-or-higher Roles Female and Minority Directors 11
Appendix
2Q-22 & FY-22 GUIDANCE Guidance Commodity Prices Used for 2Q-22 Apr-22 May-22 Jun-22 2Q-22 Avg. Crude Oil: - - - - WTI NYMEX ($/BBO) $101.64 $104.19 $102.25 $102.71 Brent ICE ($/BBO) $105.81 $107.06 $105.36 $106.09 Natural Gas: - - - - Henry Hub ($/MMBTU) $5.34 $7.27 $7.24 $6.62 Waha ($/MMBTU) $4.48 $6.11 $6.36 $5.66 Natural Gas Liquids: - - - - C2 ($/BBL) $21.37 $22.47 $22.47 $22.11 C3 ($/BBL) $54.30 $54.02 $54.08 $54.13 IC4 ($/BBL) $69.71 $72.45 $70.04 $70.75 NC4 ($/BBL) $65.41 $67.88 $66.31 $66.55 C5+ ($/BBL) $95.12 $95.34 $94.76 $95.08 Composite ($/BBL)1 $46.65 $47.39 $47.10 $47.05 2Q-22 FY-22 Production: - - Total Production (MBOE/D) 85.0 – 88.0 82.0 – 86.0 Crude Oil Production (MBO/d) 40.0 – 42.0 39.5 – 42.5 Incurred Capital Expenditures ($MM): ~$125 ~$550 Average Sales Price Realizations (excluding derivatives): - - Crude Oil (% of WTI) 100% - Natural Gas Liquids (% of WTI) 34% - Natural Gas (% of Henry Hub) 68% - Net Settlements Received (Paid) for Matured Commodity Derivatives ($MM): - - Crude Oil ($MM) ($119) - Natural Gas Liquids ($MM) ($16) - Natural Gas ($MM) ($20) - Net Income (Expense) of Purchased Oil ($MM): $0 - Operating Costs & Expenses ($/BOE): - - Lease Operating Expenses $5.35 - Production & Ad Valorem Taxes (% of Oil, NGL & Natural Gas Revenues) 6.5% - Transportation and Marketing Expenses $1.65 - General and Administrative Expenses (excluding LTIP) $1.65 - General and Administrative Expenses (LTIP Cash) $0.45 - General and Administrative Expenses (LTIP Non-Cash) $0.25 - Depletion, Depreciation and Amortization $9.75 - Note: Supports average sales price realization and derivatives guidance 13 1Current NGL composition C2 (42%), C3 (33%), IC4 (3%), NC4 (11%) and C5+ (11%)
Crude Oil Hedge Book1 (Volume in MBO; Price in $/BBO) Q2-22 Q3-22 Q4-22 BAL-22 Q1-23 Q2-23 Q3-23 Q4-23 FY-23 Brent Swaps 1,028 1,040 1,040 3,108 - - - - - WTD Price $48.34 $48.34 $48.34 $48.34 - - - - - Brent Collars 387 391 391 1,169 - - - - - WTD Floor Price $56.65 $56.65 $56.65 $56.65 - - - - - WTD Ceiling Price $65.44 $65.44 $65.44 $65.44 - - - - - WTI Swaps 884 92 92 1,068 - - - - - WTD Price $85.14 $64.40 $64.40 $81.57 - - - - - WTI Collars 846 856 856 2,558 1,530 1,547 460 460 3,997 WTD Floor Price $58.23 $58.23 $58.23 $58.23 $66.18 $66.18 $67.00 $67.00 $66.37 WTD Ceiling Price $69.39 $69.39 $69.39 $69.39 $80.29 $80.29 $84.04 $84.04 $81.16 Total Swaps/Collars 3,145 2,378 2,378 7,902 1,530 1,547 460 460 3,997 WTD Floor Price $62.36 $53.88 $53.88 $57.26 $66.18 $66.18 $67.00 $67.00 $66.37 Natural Gas Liquids Hedge Book1 (Volume in MBBL; Price in $/BBL) Q2-22 Q3-22 Q4-22 BAL-22 Q1-23 Q2-23 Q3-23 Q4-23 FY-23 Ethane Swaps 382 386 386 1,155 - - - - - WTD Price $11.42 $11.42 $11.42 $11.42 - - - - - Propane Swaps 291 294 294 880 - - - - - WTD Price $35.91 $35.91 $35.91 $35.91 - - - - - Butane Swaps 91 92 92 275 - - - - - WTD Price $41.58 $41.58 $41.58 $41.58 - - - - - Isobutane Swaps 27 28 28 83 - - - - - WTD Price $42.00 $42.00 $42.00 $42.00 - - - - - Pentane Swaps 91 92 92 275 - - - - - WTD Price $60.65 $60.65 $60.65 $60.65 - - - - - Natural Gas Hedge Book1 (Volume in MMBTU; Price in $/MMBTU) Q2-22 Q3-22 Q4-22 BAL-22 Q1-23 Q2-23 Q3-23 Q4-23 FY-23 Henry Hub Swaps 910,000 920,000 920,000 2,750,000 - - - - - WTD Price $2.73 $2.73 $2.73 $2.73 - - - - - Henry Hub Collars 7,280,000 7,360,000 7,360,000 22,000,000 3,600,000 3,640,000 3,680,000 3,680,000 14,600,000 WTD Floor Price $3.09 $3.09 $3.09 $3.09 $3.75 $3.75 $3.75 $3.75 $3.75 WTD Ceiling Price $3.84 $3.84 $3.84 $3.84 $7.88 $7.88 $7.88 $7.88 $7.88 Total Henry Hub Swaps/Collars 8,190,000 8,280,000 8,280,000 24,750,000 3,600,000 3,640,000 3,680,000 3,680,000 14,600,000 WTD Floor Price $3.05 $3.05 $3.05 $3.05 $3.75 $3.75 $3.75 $3.75 $3.75 Waha Basis Swaps 7,234,500 7,314,000 7,314,000 21,862,500 3,600,000 3,640,000 3,680,000 3,680,000 14,600,000 WTD Price ($0.36) ($0.36) ($0.36) ($0.36) ($1.52) ($1.52) ($1.52) ($1.52) ($1.52) 1Hedges executed as of 5/3/2022 Active Hedge Program to Protect Free Cash Flow 14
$3,716 $3,154 $3,902 $4,649 $5,398 SEC Pricing $55 $65 $75 $85Oil 38% NGL 31% Natural Gas 31% PD, 73% PUD, 27% 1SEC pricing $63 benchmark oil and $3.35 benchmark gas; 2Based only on wells categorized as Proved Developed as of YE-21 and decline calculated Q4 to Q4; 3 See Appendix for definitions of non-GAAP financial measures Oil Reserve Growth Driven by Strategic Portfolio Repositioning Highlights Proved reserves PV-103 improved by ~260% versus YE-20 Strategic acquisitions increased oil reserves by ~65 MMBLs, offset by the sale of 16 MBBLs, leading to an improved oil production mix PUD reserves improved driven by inventory depth and price resiliency PV-103 Reserve Value Sensitivity - $MM1 278 58 (88) 100 (30) 319 YE2020 Revisions & Extensions Sale of Reserves Purchase of Reserves 2021 Production YE2021 78% Oil Growth24% Oil 38% Oil Total Reserves and Resources - MMBOE Benchmark WTI Oil Price (Benchmark HH Gas Price assumes $3.50) Reserves by Category Annual Base Production Decline Expectations2 Reserves by Commodity FY-22 FY-23 FY-24 Howard Oil, MBO/d 57% 34% 24% Total Company 44% 29% 20% Howard Total Production, MBOE/d 53% 32% 23% Total Company 30% 20% 15% 15
Supplemental Non-GAAP Financial Measures Consolidated EBITDAX (Unaudited) Consolidated EBITDAX is a non-GAAP financial measure defined in the Company’s Senior Secured Credit Facility as net income or loss (GAAP) plus adjustments for extraordinary gains (or losses), non-cash recurring gains (or losses), depletion, depreciation and amortization expense, interest expense, any provisions for (or benefit from) income or franchise taxes, exploration expenses and other non-cash charges. Consolidated EBITDAX is used by the Company’s management for various purposes, including as a measure of operating performance and compliance under the Company’s Senior Secured Credit Facility. Additional information on the calculation of Consolidate EBITDAX can be found in the Company’s Eighth Amendment to the Senior Secured Credit Facility as filed with the SEC on April 19, 2022. The following table presents a reconciliation of net income (loss) (GAAP) to Consolidated EBITDAX (non-GAAP) for the periods presented: 16 (in thousands, unaudited) 3/31/2022 12/31/2021 9/30/2021 Net Income (loss) ($86,781) $216,276 $136,832 Plus: Share-settled equity-based compensation, net 2,053 2,066 1,811 Depletion, depreciation and amortization 73,492 74,592 62,678 Mark-to-market on derivatives: (Gain) loss on derivatives, net 325,816 (15,372) 96,240 Settlements paid for matured derivatives, net (125,370) (129,361) (92,726) Accretion expense 1,019 1,026 906 Gain on sale of oil and natural gas properties, net - - (95,223) Loss on disposal of assets, net 260 8,903 22 Interest expense 32,477 31,163 30,406 Income tax (benefit) expense (877) 3,052 2,677 Consolidated EBITDAX (non-GAAP) $222,089 $192,345 $143,623 Three months ended,
Supplemental Non-GAAP Financial Measures PV-10 (Unaudited) PV-10 is a non-GAAP financial measure that is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the standardized measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10 percent. Management believes that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to the Company's estimated proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of the Company's proved oil, NGL and natural gas assets. Further, investors may utilize the measure as a basis for comparison of the relative size and value of proved reserves to other companies. The Company uses this measure when assessing the potential return on investment related to proved oil, NGL and natural gas assets. However, PV-10 is not a substitute for the standardized measure of discounted future net cash flows. The PV-10 measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of the Company's oil, NGL and natural gas reserves of the property. 17 (in millions) December 31, 2021 Standardized measure of discounted future net cash flows $3,425 Less present value of future income taxes discounted at 10% (291) PV-10 (non-GAAP) $3,716
Supplemental Non-GAAP Financial Measures Net Debt (Unaudited) Net Debt, a non-GAAP financial measure, is calculated as the face value of long-term debt plus any outstanding letters of credit, less cash and cash equivalents. Management believes Net Debt is useful to management and investors in determining the Company’s leverage position since the Company has the ability, and may decide, to use a portion of its cash and cash equivalents to reduce debt. Net Debt as of March 31, 2022 was $1.418 billion. Net Debt to Consolidated EBITDAX (Unaudited) Net Debt to Consolidated EBITDAX, a non-GAAP financial measure, is calculated as Net Debt, including letters of credit, divided by Consolidated EBITDAX, as defined in the Company's Senior Secured Credit Facility. For the purposes of calculating Consolidated EBITDAX for the period ended March 31, 2022 calculation is the annualization of the three quarters ended March 31, 2022. Net Debt to Consolidated EBITDAX is used by the Company’s management for various purposes, including as a measure of operating performance, in presentations to its board of directors and as a basis for strategic planning and forecasting. Free Cash Flow (Unaudited) Free Cash Flow is a non-GAAP financial measure that the Company defines as net cash provided by operating activities (GAAP) before changes in operating assets and liabilities, net, less incurred capital expenditures, excluding non-budgeted acquisition costs. Free Cash Flow does not represent funds available for future discretionary use because it excludes funds required for future debt service, capital expenditures, acquisitions, working capital, income taxes, franchise taxes and other commitments and obligations. However, management believes Free Cash Flow is useful to management and investors in evaluating operating trends in its business that are affected by production, commodity prices, operating costs and other related factors. There are significant limitations to the use of Free Cash Flow as a measure of performance, including the lack of comparability due to the different methods of calculating Free Cash Flow reported by different companies. The Company is unable to provide a reconciliation of the forward-looking Free Cash Flow projection contained in this presentation to net cash provided by operating activities, the most directly comparable GAAP financial measure, because we cannot reliably predict certain of the necessary components of net cash provided by operating activities, such as changes in working capital, without unreasonable efforts. Such unavailable reconciling information may be significant. 18