Press Release

TULSA, OK, July 31, 2019 (GLOBE NEWSWIRE) -- Laredo Petroleum, Inc. (NYSE: LPI) ("Laredo" or "the Company") today announced its 2019 second-quarter results, reporting net income attributable to common stockholders of $173.4 million, or $0.75 per diluted share. Adjusted Net Income, a non-GAAP financial measure, for the second quarter of 2019 was $55.5 million, or $0.24 per diluted share. Adjusted EBITDA, a non-GAAP financial measure, for the second quarter of 2019 was $153.2 million. Please see supplemental financial information at the end of this news release for reconciliations of non-GAAP financial measures.

2019 Second-Quarter Highlights

• Completed the widely-spaced Yellow Rose package, which is outperforming a directly offset tightly-spaced package by 30% based on cumulative oil production per foot
  
  
• Produced a Company record 30,447 barrels of oil per day ("BOPD"), exceeding oil production guidance by 7% or almost 2,000 BOPD
  
  
• Reduced amount outstanding on the Company's credit facility by $35.0 million, lowering Net Debt to Adjusted EBITDA to 1.7 times^a
  
  
• Received net cash payments of $15.8 million on settlements of derivatives as the Company's hedges mitigated the impact of commodity price declines
  
  
• Reduced controllable cash costs of combined unit lease operating expenses ("LOE") and unit cash general and administrative expenses ("G&A") to $4.69 per barrel of oil equivalent ("BOE"), a 23% decrease from full-year 2018 results of $6.07 per BOE

"The second quarter of 2019 fully demonstrated the results of the strategic transformation Laredo began late last year," stated Randy A. Foutch, Chairman and Chief Executive Officer. "Well productivity dramatically improved from 2018 as we widened spacing, unit cash G&A decreased 36% from full-year 2018 after we reduced personnel expenses, we paid down $35 million of debt as we generated free cash flow during the quarter, and now we expect to generate $30 million in free cash flow for full-year 2019."

"We believe there is still room to improve on these results," explained Jason Pigott, President. "We are refining our development focus to reduce the risk of vertical interference in our Upper/Middle Wolfcamp drilling and we are returning to areas of the Cline where economics have become competitive as costs have come down. High-grading inventory and further reducing costs to improve returns facilitate our top priorities of measured oil growth with free cash flow generation and replenishing our high-quality inventory through bolt-on transactions."

Guidance Update

In the first half of 2019, Laredo has surpassed the Company's production and cash flow generation expectations and is in line with capital expenditure expectations. Accordingly, full-year 2019 oil and total production guidance and free cash flow expectations are being increased. Laredo now expects oil production for full-year 2019 to be flat compared to full-year 2018, an increase from previous guidance of down 2%. Total production is now expected to grow 14% versus previous guidance of 11% growth. These increases in production expectations are anticipated to drive free cash flow generation^b of $30 million for full-year 2019 while operating within our $465 million capital budget, excluding non-budgeted acquisitions.

The Company's decision to widen development spacing to improve well productivity, combined with sustainable operational efficiency gains that have shortened cycle times, is driving these increased production expectations. Increasing production assumptions, coupled with Laredo's robust 2019 commodity hedges that mitigate the impact of declining commodity prices, underpins Laredo's confidence in these free cash flow projections.

E&P Update

During the second quarter of 2019, Laredo completed 12 gross (11.5 net) horizontal wells with an average lateral length of approximately 11,600 feet. These 12 wells were developed in two packages, both utilizing the Company's wider-spaced development plan. The Yellow Rose package, an eight-well co-development package, began flowback at the end of April. After more than 100 days of production, oil productivity per lateral foot is outperforming an offset package of tighter-spaced wells completed in 2018 by more than 30%, reinforcing the Company's confidence in its Upper/Middle Wolfcamp type curve.

Oil and total production both exceeded second-quarter 2019 guidance, driven by the performance of the Yellow Rose package and wells being put on production earlier than anticipated due to reduced cycle times. Second-quarter 2019 oil production was 30,447 BOPD and total production was 82,259 BOE per day, exceeding Company-issued guidance by 7% and 5%, respectively.

In the third quarter of 2019, Laredo expects to complete 11 gross (11 net) widely-spaced horizontal wells with an average completed lateral length of approximately 10,100 feet. The first package is a four-well, single zone development package in the Middle Wolfcamp, infilling below a previous Upper Wolfcamp development package. The second is a seven-well, Middle Wolfcamp co-development package. These wells will further the Company's successful transition to wider-spacing development and will provide additional valuable information on optimal vertical spacing.

Laredo continues to sharpen its focus on high-grading development to optimize returns and minimize spacing risk. One important refinement is the Company's evolving approach to Upper/Middle Wolfcamp development. Using both proprietary and third-party vertical spacing data to quantify productivity impacts of the vertical distances between horizontal wells, the Company's Upper/Middle Wolfcamp co-development strategy will now target three landing points rather than four. Laredo expects this approach to reduce risks associated with vertical interference and increase the certainty of productivity expectations.

Additionally, the Company is planning to return to regions of higher productivity in the Cline formation that are expected to generate returns commensurate with Upper/Middle Wolfcamp targets as drilling and completions costs have decreased. These assumptions have been incorporated into a new Cline type curve for 10,000-foot lateral horizontal wells in these areas. Total production expectations for the new regional Cline type curve are 1.0 MMBOE for the life of the well, comprised of approximately 40% oil, with more than 60% of expected oil production recovered in the first five years of the life of the well. The Company expects to begin incorporating some of these Cline locations into its 2020 development program.

Laredo's successful shift to wider-spaced development is expected to drive productivity improvements versus tighter-spaced development, as demonstrated by the Yellow Rose package. High-grading inventory, prioritizing development based on the highest rate of return targets and replenishing inventory through targeted bolt-on leasing and acquisitions are expected to sustain these improvements and drive the Company's long-term goals of moderate oil production growth and free cash flow generation.

Laredo Midstream Services

Laredo's investments in field infrastructure through its wholly-owned Laredo Midstream Services LLC ("LMS")  subsidiary drive both environmental and financial benefits for the Company. Through the first half of 2019, oil and water gathering pipelines owned or contracted by LMS gathered more than 18,000,000 barrels of oil and water, eliminating the need for more than 130,000 truckloads within Laredo's leasehold and producing a net financial benefit to the Company of approximately $18 million. LMS' water recycling plants processed more than 3,100,000 barrels of water in the first six months of 2019 and Laredo utilized 5,900,000 barrels of recycled water in completions activities over the same period, reducing capital expenditures and LOE by a combined $2.2 million.

The Company continues to improve upon its peer-leading unit LOE, driven by the field infrastructure providing a substantial and sustainable financial benefit. Unit LOE in the first half of 2019 was $3.24 per BOE, a 14% reduction from the first half of 2018. Laredo estimates field infrastructure benefits reduced unit LOE for the first half of 2019 by $0.57 per BOE.

2019 Capital Program

During the second quarter of 2019, Laredo invested $116 million in drilling and completions activities. Other expenditures incurred during the quarter included $4 million in land-related expenditures and data acquisition, $8 million in infrastructure, including LMS investments, and $4 million in other capitalized costs. Additionally, the Company completed property acquisitions for $3 million that were not previously budgeted.

Total costs incurred of $296 million in the first half of 2019, excluding non-budgeted acquisitions, put the Company on pace to deliver on its plan to complete 52 wells within the $465 million capital budget and deliver $30 million in free cash flow for full-year 2019, excluding non-budgeted acquisitions.

Liquidity

At June 30, 2019, the Company had outstanding borrowings of $235 million on its $1.1 billion senior secured credit facility, resulting in available capacity, after reductions for outstanding letters of credit, of $850 million. Including cash and cash equivalents of $56 million, total liquidity was $906 million.

Subsequent to the end of the second quarter of 2019, Laredo paid down an additional $20 million on its credit facility, resulting in outstanding borrowings of $215 million. Including cash and cash equivalents at July 31, 2019 of $40 million and after reductions for outstanding letters of credit, total liquidity was $910 million.

To date, the Company has repaid $55 million of the $80 million borrowed in the first quarter of 2019 and expects to fully repay the $80 million by the end of the year.

Commodity Derivatives

Laredo has hedged approximately 95% of anticipated oil production at a weighted-average floor price of $60.42 per barrel for the remainder of 2019 and approximately 75% of anticipated oil production at a weighted-average floor price of $58.79 for full-year 2020. Additionally, Laredo has hedged approximately 70% of anticipated natural gas production and 65% of anticipated natural gas liquids ("NGL") production for the remainder of 2019 and approximately 45% of anticipated natural gas production and approximately 30% of anticipated NGL production for full-year 2020.

Additional details of the Company's hedge positions are included in the current Corporate Presentation available on the Company's website at www.laredopetro.com.

Guidance

The Company is increasing its anticipated full-year 2019 total production growth guidance to 14% and oil production guidance to flat as compared to full-year 2018. The table below reflects the Company's guidance for the third quarter of 2019.

Conference Call Details

On Thursday, August 1, 2019, at 7:30 a.m. CT, Laredo will host a conference call to discuss its second-quarter 2019 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 7258021, approximately 10 minutes prior to the scheduled conference time. A telephonic replay will be available approximately two hours after the call on August 1, 2019 through Thursday, August 8, 2019. Participants may access this replay by dialing 855.859.2056, using conference code 7258021.

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, and midstream and marketing services, 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 subject 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, 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, 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, the increase in service and supply costs, tariffs on steel, pipeline transportation constraints in the Permian Basin, hedging activities, possible impacts of litigation, the suspension or discontinuance of share repurchases at any time and other factors, including those and other risks described in its Annual Report on Form 10-K for the year ended December 31, 2018, 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. Laredo does not intend to, and disclaims any obligation to, update or revise any forward-looking statement.

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" and "estimated ultimate recovery," or "EURs," 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 added to proved reserves, largely from a specified resource play. 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 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.Estimates of ultimate recovery 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%. The actual results may vary considerably and should not be considered to represent the fair market value of the Company’s proved reserves.

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1. BOE is calculated using a conversion rate of six Mcf per one Bbl.
   
   
2. The numbers presented are based on actual amounts and are not calculated using the rounded numbers presented in the table above.
   
   
3. Actual prices received when control passes to the purchaser/customer adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.
   
   
4. Price reflects the after-effects of our derivative transactions on our average sales prices. Our calculation of such after-effects includes settlements of matured derivatives during the respective periods in accordance with GAAP and an adjustment to reflect premiums incurred previously or upon settlement that are attributable to derivatives that settled during the respective periods.
   
   
5. For the three and six months ended June 30, 2019, non-cash stock-based compensation, net, excluding forfeitures related to our April 2019 organizational restructuring, on a per BOE sold basis was $0.75 and $0.91, respectively.
   
   
6. On a per BOE basis, average cash margins are calculated as average sales price less, (i) lease operating expenses, (ii) production and ad valorem taxes, (iii) transportation and marketing expenses, (iv) midstream service expenses and (v) cash general and administrative.

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1. See Note 3.a in the second-quarter 2018 Quarterly Report for discussion of the Company's acquisitions of evaluated and unevaluated oil and natural gas properties during the three months ended June 30, 2018.

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1. Adjusted income tax expense is calculated by applying a statutory tax rate of 22% for each of the periods ended June 30, 2019 and 2018.

Adjusted EBITDA (Unaudited)

Adjusted EBITDA is a non-GAAP financial measure that we define as net income or loss plus adjustments for income taxes, depletion, depreciation and amortization, non-cash stock-based compensation, net, accretion expense, mark-to-market on derivatives, premiums paid for derivatives, interest expense, gains or losses on disposal of assets 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 discretionary use because those funds are 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 excluded from the calculation of such term, which 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, the lack of comparability of results of operations to different companies and 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 (GAAP) to Adjusted EBITDA (non-GAAP):

^a Net Debt to Adjusted EBITDA

Net debt to Adjusted EBITDA is calculated as net debt as of June 30, 2019 divided by trailing twelve-month Adjusted EBITDA ending June 30, 2019 of $569 million. Net debt as of June 30, 2019 was $979 million, calculated as the face value of debt of $1.035 billion reduced by cash and cash equivalents of $56 million. See above for a definition of Adjusted EBITDA.

^b Projected Free Cash Flow

Projected free cash flow is calculated as estimated full-year 2019 cash flows from operating activities before changes in assets and liabilities, less cash and non-cash capital investments made during the period, excluding non-budgeted acquisitions. Management believes this is useful to investors in evaluating the operating trends in its business due to production, commodity prices, operating costs and other related factors.

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

Source: Laredo Petroleum, Inc.