Press Release

TULSA, OK, Aug. 05, 2020 (GLOBE NEWSWIRE) -- Laredo Petroleum, Inc. (NYSE: LPI) ("Laredo" or "the Company") today announced its second-quarter 2020 results. For the second quarter of 2020, the Company reported a net loss attributable to common stockholders of $545.5 million, or $46.75 per diluted share. Adjusted Net Income, a non-GAAP financial measure, for the second quarter of 2020 was $28.4 million, or $2.43 per adjusted diluted share. Adjusted EBITDA, a non-GAAP financial measure, for the second quarter of 2020 was $132.8 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.

Additionally, the Company filed an amended Form 10-Q for the quarter ended March 31, 2020, originally filed with the Securities Exchange Commission (the "SEC") on May 7, 2020. The filing corrects a $160 million understatement  of the full cost ceiling impairment expense for the quarter ended March 31, 2020, which caused an understatement of the balances of accumulated depletion and impairment and accumulated deficit, and a corresponding overstatement of the same amount to both net income and the balance of our oil and natural gas properties as of March 31, 2020. This error was isolated to the Company's first-quarter estimate of the full cost impairment and had no impact on the Company's prior financial statements, including the 2019 annual report on Form 10-K. This press release gives effect to the corrections to the amounts included in the amended first quarter report. Please refer to the Form 10-Q/A for the period ended March 31, 2020 and Form 8-K, both filed with the SEC on August 5, 2020, for additional information.

Second-Quarter 2020 Highlights

• Received $86.9 million from settlements of matured commodity derivatives, resulting in an average hedged sales price of $21.09 per barrel of oil equivalent ("BOE"), a 92% increase versus an average unhedged sales price of $10.99 per BOE in the same period
• Reduced unit lease operating expenses ("LOE") to $2.40 per BOE, a 24% decrease from the second quarter of 2019
• Reduced unit general and administrative expenses ("G&A") to $1.24 per BOE, a 16% decrease from the second quarter of 2019
• Produced an average of 31,241 barrels of oil per day ("BOPD"), an increase of 3% from the second quarter of 2019
• Produced an average of 94,117 BOE per day, an increase of 14% from the second quarter of 2019

"The macro environment during the second quarter of 2020 was unprecedented in its difficulties for the energy industry," stated Jason Pigott, President and Chief Executive Officer. "Our success managing through this turbulence highlights the benefits of how we run our business. We mitigate commodity price risk with a robust hedging program, maintain operational flexibility and focus on driving additional costs out of the business."

"We are excited to demonstrate the capital efficiency of our Howard County acquisition as we resume development activities and begin completions operations later in the third quarter," continued Mr. Pigott. "As we expect to maintain a stable drilling and completions cadence in 2021, we remain focused on operating within cash flow and securing those cash flows with a consistent hedging program. Steady completions activity in Howard County, combined with increased commodity prices and hedges in 2021, supports an estimated $120 million in additional cash flow in 2021 and should return our oil production to full-year 2019 levels. In combination with growing cash flows, our focus is on strengthening our balance sheet as we evaluate acquisition and deleveraging opportunities and improving our debt-to-equity ratio."

2020/2021 Operational Activity Levels

In early 2020, the Company significantly reduced planned operational activities as commodity prices suffered from historic declines amid COVID-19 related demand destruction and OPEC+ pricing and supply decisions which dramatically reduced expected returns on capital investments. A subsequent increase in commodity prices, paired with service cost reductions, has driven expected returns on Laredo's Howard County acreage back to levels that support a resumption of activity. Beginning in September 2020, the Company plans to operate a completions crew in Howard County.

Laredo now expects to complete a 15-well package in Howard County during the fourth quarter of 2020. This additional activity is expected to improve the Company's production beginning in the first quarter of 2021. Laredo now anticipates capital expenditures for full-year 2020 to be $340 - $350 million and to operate within cash flow, excluding non-budgeted acquisitions.

At current service costs and commodity prices, the Company plans to return to a normalized operational cadence of two rigs and one completions crew at the beginning of 2021. This stable activity level eliminates the disruptions associated with either front-loading or halting completions during the year, drives operational and capital efficiencies, and balances the number of wells drilled with those completed. Planned activity in 2021 will be focused on the Company's oily, high-return Howard County acreage, with 50 - 55 completions anticipated in 2021.

Laredo expects this 2021 activity to be accomplished with total capital expenditures of $325 - $350 million and to generate full-year 2021 oil production of 27.0 - 29.0 MBOPD. To protect the returns and cash flow associated with this development program, the Company has entered into additional oil hedges and currently has 20,150 BOPD hedged for 2021 at a weighted-average Brent floor price of $51 per barrel.

Operations Summary

During the second quarter of 2020, the Company completed 5 gross (4.6 net) horizontal wells, all on its recently- acquired western Glasscock acreage. Early production results were restrained by the sizing of field infrastructure built by the previous operator. After installing appropriately-sized flow lines for the five-well package, artificial lift operations have been optimized and wells are performing at or above initial productivity expectations.

Laredo produced 94,117 BOE per day in the second quarter of 2020, including oil production of 31,241 BOPD, exceeding the high-end of guidance by 10% and 2%, respectively. Production results were driven by the sustained outperformance of well packages developed with the Company's area-specific optimized spacing and completions design.

The Company is currently operating one drilling rig, located in Howard County. A completions crew will be deployed to Howard County late in the third quarter of 2020 and will begin completions operations on a 15-well package. Based on current service costs, well costs are expected to be $550 per lateral foot.

Unit LOE for second-quarter 2020 decreased to $2.40 per BOE, a reduction of 14% from the first quarter of 2020. Production expenses on the Company's established acreage position benefit from Laredo's prior investments in field infrastructure and the use of low-cost gas lift for artificial lift. As the Company transitions to Howard County, unit LOE is expected to increase moderately as utilization of ESP's for artificial lift is preferred to optimize the oilier production from these wells. Unit LOE in Howard County is expected to be approximately $4.00 per BOE, with combined unit LOE for the Company expected to remain below $3.00 per BOE for full-year 2021.

G&A Expenses

Laredo continues to focus on further improving the Company's peer-leading cost structure. As previously announced, Laredo took steps to preserve margins in this challenging commodity price environment. A combination of an approximate 8% headcount reduction, Company-wide salary reductions and a decrease in Director's fees drove unit G&A to $1.24 per BOE. The Company expects G&A expenses for full-year 2020 to be approximately 10% less than full-year 2019 levels.

Second-Quarter 2020 Costs Incurred

During the second quarter of 2020, excluding non-budgeted acquisitions, total costs incurred were $78 million, comprised of $63 million in drilling and completions activities, $3 million in land, exploration and data related costs, $6 million in infrastructure, including Laredo Midstream Services investments, and $6 million in other capitalized costs. Additionally, a non-budgeted acquisition of $1 million was closed during the quarter.

Increased Oil Hedges

The Company maintains an active, multi-year commodity and interest rate derivatives strategy to manage commodity price risk and support operating cash flows. Laredo utilizes only puts, swaps and collars and does not enter into three-way collars, which limit protection in a rapidly declining price environment.

For the remainder of 2020, Laredo has hedged 4.8 million barrels of oil, with 3.6 million barrels of oil swapped at a weighted-average price of $59.50 WTI per barrel and 1.2 million barrels of oil swapped at a weighted-average price of $63.07 Brent per barrel. For 2021, the Company has hedged approximately 70% of expected oil production, with 7.4 million barrels of oil at a weighted-average floor price of $51.11 Brent per barrel.

Please see the table in the appendix of Laredo's Second-Quarter 2020 Earnings Presentation posted to the Company's website for the full details of the Company's commodity derivatives.

Liquidity

At June 30, 2020, the Company had outstanding borrowings of $275 million on its $725 million senior secured credit facility, resulting in available capacity, after the reduction for outstanding letters of credit, of $406 million. Including cash and cash equivalents of $16 million, total liquidity was $422 million.

At August 4, 2020, the Company had outstanding borrowings of $300 million on its $725 million senior secured credit facility, resulting in available capacity, after the reduction for outstanding letters of credit, of $381 million. Including cash and cash equivalents of $21 million, total liquidity was $402 million.

Third-Quarter and Full-Year 2020 Guidance

The table below reflects the Company's quarterly and full-year guidance for total and oil production for 2020.

The table below reflects the Company's guidance for selected revenue and expense items for the third quarter of 2020.

Conference Call Details

On Thursday, August 6, 2020, at 7:30 a.m. CT, Laredo will host a conference call to discuss its second-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 4172567, 10 minutes prior to the scheduled conference time. A telephonic replay will be available two hours after the call on August 6, 2020 through Thursday, August 13, 2020. Participants may access this replay by dialing 855.859.2056, using conference code 4172567.

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. This press release and any accompanying disclosures may include or reference certain forward-looking, non-GAAP financial measures, such as Free Cash Flow, Adjusted Net Income and Adjusted EBITDA, and certain related estimates regarding future performance, results and financial position. 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 repurchases, if any, of securities from time to time and other factors, including those and other risks described in its Annual Report on Form 10-K for the year ended December 31, 2019, Amendment No. 1 to its Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, its Quarterly Report on Form 10-Q for the quarter ended June 30, 2020 and those set forth from time to time in other filings with the Securities and Exchange Commission ("SEC"). These documents are available through Laredo's website at www.laredopetro.com under the tab "Investor Relations" or through the SEC's Electronic Data Gathering and Analysis Retrieval System at www.sec.gov. Any of these factors could cause Laredo's actual results and plans to differ materially from those in the forward-looking statements. Therefore, Laredo can give no assurance that its future results will be as estimated. Any forward-looking statement speaks only as of the date on which such statement is made. Laredo does not intend to, and disclaims any obligation to, correct update or revise any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

The SEC generally permits oil and natural gas companies, in filings made with the SEC, to disclose proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions and certain probable and possible reserves that meet the SEC's definitions for such terms. In this press release and the conference call, the Company may use the terms "resource potential," "resource play," "estimated ultimate recovery" or "EURs," and "type curve," each of which the SEC guidelines restrict from being included in filings with the SEC without strict compliance with SEC definitions. These terms refer to the Company’s internal estimates of unbooked hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques. "Resource potential" is used by the Company to refer to the estimated quantities of hydrocarbons that may be added to proved reserves, largely from a specified resource play potentially supporting numerous drilling locations. A "resource play" is a term used by the Company to describe an accumulation of hydrocarbons known to exist over a large areal expanse and/or thick vertical section potentially supporting numerous drilling locations, which, when compared to a conventional play, typically has a lower geological and/or commercial development risk. EURs are based on the Company’s previous operating experience in a given area and publicly available information relating to the operations of producers who are conducting operations in these areas. Unbooked resource potential or EURs do not constitute reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or SEC rules and do not include any proved reserves. Actual quantities of reserves that may be ultimately recovered from the Company’s interests may differ substantially from those presented herein. Factors affecting ultimate recovery include the scope of the Company’s ongoing drilling program, which will be directly affected by the availability of capital, decreases in oil, natural gas liquids and natural gas prices, well spacing, drilling and production costs, availability and cost of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals, negative revisions to reserve estimates and other factors as well as actual drilling results, including geological and mechanical factors affecting recovery rates. EURs from reserves may change significantly as development of the Company’s core assets provides additional data. In addition, our production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases. "Type curve" refers to a production profile of a well, or a particular category of wells, for a specific play and/or area. In addition, the Company’s production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases. The "standardized measure" of discounted future new cash flows is calculated in accordance with SEC regulations and a discount rate of 10%. Actual results may vary considerably and should not be considered to represent the fair market value of the Company’s proved reserves.

Unless otherwise specified, references to “average sales price” refer to average sales price excluding the effects of our derivative transactions.

All amounts, dollars and percentages presented in this press release are rounded and therefore approximate.

Laredo Petroleum, Inc.
Selected operating data

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(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 our commodity derivative transactions on our average sales prices. Our 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.

Laredo Petroleum, Inc.
Condensed consolidated statements of operations

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(1) Net income (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.

Laredo Petroleum, Inc.
Condensed consolidated statements of cash flows

Laredo Petroleum, Inc.
Total Costs Incurred

The following tables present the components of our costs incurred, excluding non-budgeted acquisition costs, for the periods presented and corresponding changes:

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 us, 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, our 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.  

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:

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(1)     Includes capitalized share-settled equity-based compensation and asset retirement costs.

Adjusted Net Income (Unaudited)

Adjusted Net Income is a non-GAAP financial measure we use to evaluate performance, prior to income taxes, mark-to-market on derivatives, premiums paid for commodity derivatives that matured during the period, impairment expense, gains or losses on disposal of assets and other non-recurring income and expenses and after applying adjusted income tax expense. We believe Adjusted Net Income helps investors in the oil and natural gas industry to measure and compare our 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 income (loss) before income taxes (GAAP) to Adjusted Net Income (non-GAAP):

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(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 June 30, 2020 and 2019.

Adjusted EBITDA (Unaudited)

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) for the periods presented:

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(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.

Forecasted Free Cash Flow
Forecasted Free Cash Flow, a non-GAAP financial measure, is calculated as estimated cash flows from operating activities before changes in assets and liabilities, less estimated costs incurred, excluding non-budgeted acquisition costs, made during the period. Management believes this 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. We do not provide guidance on the reconciling items between forecasted cash provided by operating activities and forecasted Free Cash Flow due to the uncertainty regarding timing and estimates of these items. Therefore, we cannot reconcile forecasted cash provided by operating activities to forecasted Free Cash Flow without unreasonable effort.

Contact:
Ron Hagood:  (918) 858-5504 - RHagood@laredopetro.com 

Source: Laredo Petroleum, Inc.