Laredo Petroleum Announces 2016 Third-Quarter Financial and Operating Results

TULSA, O.K., Nov. 02, 2016 (GLOBE NEWSWIRE) -- Laredo Petroleum, Inc. LPI ("Laredo" or "the Company") today announced its 2016 third-quarter results, reporting net income attributable to common stockholders of $9.5 million, or $0.04 per diluted share. Adjusted Net Income, a non-GAAP financial measure, for the third quarter of 2016 was $28.4 million, or $0.12 per diluted share. Adjusted EBITDA, a non-GAAP financial measure, for the third quarter of 2016 was $118.0 million. Please see supplemental financial information at the end of this news release for reconciliations of non-GAAP financial measures.

2016 Third-Quarter Highlights

• Produced a Company record 51,276 barrels of oil equivalent ("BOE") per day and increased anticipated production growth for full-year 2016 to approximately 10%
• Completed 10 horizontal development wells with an average completed lateral length of approximately 10,900 feet, including four wells drilled with lateral lengths greater than 13,000 feet
• Reduced unit lease operating expenses ("LOE") to $3.85 per BOE, down approximately 37% from the third-quarter 2015 rate of $6.09 per BOE and down approximately 13% from the second-quarter 2016 rate of $4.43 per BOE
• Recognized approximately $6.0 million in cash benefits from Laredo Midstream Services, LLC ("LMS") field infrastructure investments through reduced costs and increased revenue
• Grew transported volumes on the Medallion-Midland Basin pipeline system (defined below) to 117,862 barrels of oil per day ("BOPD") on average for the quarter, an increase of approximately 114% from 55,164 BOPD in the third quarter of 2015
• Received approximately $41.6 million of net cash settlements, net of premiums paid, on commodity derivatives that matured during third-quarter 2016, increasing the average sales price for oil by $18.47 per barrel and for natural gas by $0.24 per thousand cubic feet compared to pre-hedged average sales prices

"Third quarter results again demonstrated the benefits of the Company's prior strategic investments in data and infrastructure," commented Randy A. Foutch, Chairman and Chief Executive Officer. "Continued refinement of

Laredo's multivariate Earth Model analysis of data collected throughout eight years of development activity has enabled the identification of multiple landing points per zone and optimized completions driving recent results, on average, more than 30% above type curve in the Upper and Middle Wolfcamp and Cline shale zones. Field infrastructure investments have helped lower unit LOE almost 50% since the beginning of 2015. To take advantage of these tremendous capital efficiency improvements and accelerate value creation, Laredo is adding a fourth horizontal rig beginning in mid November. We anticipate the additional cash flows will be protected by Laredo's outstanding hedge position and the increased activity is being accomplished without increasing the Company's capital budget."

Operational Update

In the third quarter of 2016, Laredo produced a Company record 51,276 BOE per day. The Company completed 10 horizontal development wells with an average working interest of approximately 98%, including seven with a completed lateral length greater than 10,000 feet and nine utilizing 2,400 pounds of proppant per lateral foot. Production and capital efficiency again benefited from Laredo's contiguous acreage position which enables the drilling of longer laterals and the continued refinement of the multivariate Earth Model analysis to optimize completions.

Laredo's industry-leading data collection efforts are driving recent production results as multivariate Earth Model analysis continues to incorporate additional geoscience and engineering parameters that optimize both well placement and completion design. The ongoing Hydraulic Fracture Test Site project on Laredo leasehold with the Gas Technology Institute is a $23 million joint industry project in which Laredo led operational and data collection efforts. The project has generated a world-class dataset proprietary to consortium members, including collecting approximately 600 feet of core through hydraulically fractured rock. As the Company utilizes this data in multivariate Earth Model analysis and in conjunction with completions and reservoir modeling, this process will further the evolution of Laredo's development planning. This integrated modeling is moving completion design beyond perforation cluster spacing and proppant loading to include fracture geometry, growth and behavior, enabling the testing of multiple completion designs to maximize capital efficiency and project value.

The Company has implemented a managed drawdown protocol that both limits initial choke settings and restricts the amount the choke is opened as the well produces. While this can reduce initial production ("IP") rates and delay assigning peak production rates, it is intended to enhance primary fracture conductivity, thereby improving production and recoveries over the life of the well. Laredo is evaluating the effect of managed drawdown and the associated benefit to well economics.

Seven of the 10 horizontal wells completed in the third quarter of 2016 were completed late in the quarter and have not achieved peak IP rates although the Company is very encouraged with preliminary production data. These seven wells all utilized optimized completions with 2,400 pounds of proppant per lateral foot and included four wells with drilled lateral lengths of greater than 13,000 feet. Three of the 10 horizontal wells completed in the third quarter of 2016 have generated sufficient production data to compare to Company type curves.

The G.Schwartz 17-8-1NC, drilled in the Cline shale with a completed lateral length of approximately 9,900 feet, utilized the Earth Model to optimize the completion and used 1,800 pounds of proppant per lateral foot. The well produced a 30-day peak IP rate of 1,639 BOE per day and is currently performing at 140% of the 1.0 million BOE 10,000-foot Cline type curve, adjusted for lateral length. Enhanced production from the application of multivariate Earth Model analysis and optimized completions, coupled with more efficient development drilling, is enabling the development of the Cline shale at returns approaching those achieved in the Upper and Middle Wolfcamp zones.

The Sugg-A-208-209-1SU and Sugg-E-208-207-1NM were drilled in the Upper Wolfcamp and Middle Wolfcamp formations, respectively, utilizing multivariate Earth Model analysis to optimize completions and testing 2,400 pounds of proppant per lateral foot. The Sugg-A-208-209-1SU had a completed lateral length of approximately 7,600 feet and is currently performing at 161% of type curve, adjusted for lateral length. The Sugg-E-208-207-1NM had a completed lateral length of approximately 7,500 feet and is currently performing at 140% of type curve. The Company is encouraged by the early results of higher proppant loads in these wells and will evaluate longer-term data as completion optimization techniques are further refined.

Laredo continues to materially reduce unit LOE which decreased to $3.85 per BOE from $6.09 per BOE in the third quarter of 2015. Investments in water handling infrastructure along production corridors and an intense focus on best practices to reduce well failures have contributed to the operational cost improvements.

Laredo entered the fourth quarter of 2016 operating three horizontal rigs and subsequently added a fourth horizontal rig that is expected to spud its first well in mid November. The Company does not expect the addition of this rig to impact production in the fourth quarter of 2016. Drilling cost savings realized throughout 2016 are expected to fund the additional capital expenditures associated with the increased rig count, leaving the Company's 2016 capital budget unchanged at $420 million.

The Company expects to complete 10 horizontal wells during the fourth quarter of 2016 with an average lateral length of approximately 9,200 feet and an average working interest of approximately 95%. Four of the wells have been completed and are anticipated to contribute meaningfully to production during the quarter. The remaining six wells are being drilled and completed as a package that is expected to begin flowback late in the fourth quarter of 2016.

Laredo Midstream Services Update

Laredo's development strategy of investing in field infrastructure along production corridors and concentrating drilling around those corridors continues to drive material financial and operating benefits for the Company. LMS' oil and water gathering assets enable the use of highly efficient multi-well packages that reduce capital and operating costs and average cycle time per well. Execution of these multi-well packages would be impractical without the ability of LMS to gather large volumes of oil and water by pipe. During the third quarter of 2016, LMS gathered 69% of the Company's gross operated oil production and 67% of total produced water and generated approximately $6.0 million of total cash benefit for the Company. Savings related to LMS infrastructure reduced unit LOE by approximately 12%, or $0.52 per BOE during the third quarter of 2016.

Transported volumes on the Medallion Gathering & Processing, LLC pipeline system ("Medallion-Midland Basin pipeline system"), in which LMS owns a 49% interest, grew to an average of 117,862 BOPD, an increase of approximately 114% from the third quarter of 2015 and up 19% from the second quarter of 2016. The system is expected to be transporting approximately 140,000 BOPD by the end of 2016 and to grow transported volumes 50% to 60% by the end of 2017.

2016 Capital Program

During the third quarter of 2016, Laredo invested approximately $79 million in exploration and development activities, approximately $116 million of the $125 million purchase price in a previously announced bolt-on land acquisition and approximately $17 million in infrastructure held by LMS, including the Medallion-Midland Basin pipeline system.

Liquidity

At September 30, 2016, the Company had cash and equivalents of approximately $30 million and undrawn capacity under the senior secured credit facility of $745 million.

On October 24, 2016, in connection with the regular semi-annual redetermination of the Company's senior secured credit facility, lenders reaffirmed the Company's borrowing base at $815 million with the Company's elected commitment remaining unchanged at $815 million. At November 1, 2016, the Company had cash and equivalents of approximately $10 million and undrawn capacity under the senior secured credit facility of $745 million, resulting in total liquidity of approximately $755 million.

Commodity Derivatives

Laredo maintains an active hedging program to reduce the variability in its anticipated cash flow due to fluctuations in commodity prices. At September 30, 2016, the Company had hedges in place for the fourth quarter of 2016 for 1,861,350 barrels of oil at a weighted-average floor price of $67.13 per barrel and 4,692,000 million British thermal units ("MMBtu") of natural gas at a weighted-average floor price of $3.00 per MMBtu. In addition, the Company had a meaningful level of anticipated production hedged for 2017 and 2018.

At September 30, 2016, for 2017, the Company had hedges in place covering 5,684,875 barrels of oil at a weighted-average floor price of $57.01 per barrel, 18,771,000 MMBtu of natural gas at a weighted-average floor price of $2.65 per MMBtu, 444,000 barrels of ethane at $11.24 per barrel and 375,000 barrels of propane at $22.26 per barrel. Subsequently, the Company hedged an additional 1,168,000 barrels of oil and 3,723,000 MMBtu of natural gas for 2017 and currently has 6,852,875 barrels of oil hedged for 2017 at a weighted-average floor price of $55.82 per barrel and 22,494,000 MMBtu of natural gas hedged for 2017 at a weighted-average floor price of $2.70 per MMBtu. A large portion of the Company's 2017 oil hedges retain the potential benefit of an increase in the price of oil with 3,796,000 barrels structured as collars with a weighted-average ceiling price of $86.00 per barrel and 1,049,375 barrels covered by puts and do not have a ceiling.

At September 30, 2016, for 2018, the Company had hedges in place covering 2,144,375 barrels of oil at a weighted-average floor price of $55.98 per barrel and 12,855,500 MMBtu of natural gas at a weighted-average floor price of $2.50 per MMBtu.

Fourth-Quarter 2016 Guidance

The table below reflects the Company's guidance for the fourth quarter of 2016:

Conference Call Details

On Thursday, November 3, 2016, at 7:30 a.m. CT, Laredo will host a conference call to discuss its third-quarter 2016 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, using conference code 99103479, approximately 10 minutes prior to the scheduled conference time. International participants should dial 253.336.8309, also using conference code 99103479. A telephonic replay will be available approximately two hours after the call on November 3, 2016 through Thursday, November 10, 2016. Participants may access this replay by dialing 855.859.2056, using conference code 99103479.

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 the transportation of oil and natural gas from such 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 subject of this release, including in the conference call referenced herein, 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 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. 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, and other factors, including those and other risks described in its Annual Report on Form 10-K for the year ended December 31, 2015, and those set forth from time to time in other filings with the Securities 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, drilling and production costs, availability 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 unproved 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.

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(1) BOE is calculated using a conversion rate of six Mcf per one Bbl.

(2) The volumes presented are based on actual results and are not calculated using the rounded numbers presented in the table above.

(3) Realized oil, NGL and natural gas prices are the actual prices realized at the wellhead adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. The prices presented are based on actual results and are not calculated using the rounded numbers presented in the table above.

(4) Hedged prices reflect the after-effect of our hedging transactions on our average sales prices. Our calculation of such after-effects includes current period settlements of matured derivatives in accordance with GAAP and an adjustment to reflect premiums incurred previously or upon settlement that are attributable to instruments that settled in the period. The prices presented are based on actual results and are not calculated using the rounded numbers presented in the table above.

Laredo Petroleum, Inc.
Costs incurred

Costs incurred in the acquisition, exploration and development of oil, NGL and natural gas assets are presented below:

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(1) Evaluated property acquisition costs include $1.1 million in asset retirement obligations for the three and nine months ended September 30, 2016.

(2) Development costs include $0.3 million in asset retirement obligations for the three months ended September 30, 2016 and 2015 and $0.5 million and $1.3 million for the nine months ended September 30, 2016 and 2015, respectively.

Laredo Petroleum, Inc.
Supplemental reconciliation of GAAP to non-GAAP financial measures

Non-GAAP financial measures

The non-GAAP financial measures of 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 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 flow from operating activities. Adjusted Net Income or 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.

Adjusted Net Income (Unaudited)

Adjusted Net Income is a non-GAAP financial measure we use to evaluate performance, prior to deferred income taxes, gains or losses on derivatives, cash settlements of matured derivatives, cash settlements on early terminated derivatives, cash premiums paid for derivatives, impairment expense, restructuring expenses, loss on early redemption of debt, buyout of minimum volume commitment, gains or losses on disposal of assets, write-off of debt issuance costs and bad debt expense 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.

Including a higher weighted average shares outstanding in the denominator of a diluted per-share computation results in an anti-dilutive per share amount when an entity is in a loss position. As such, our net income (loss) (GAAP) per common share calculation utilizes the same denominator for both basic and diluted net income (loss) per common share. However, our calculation of Adjusted Net Income (non-GAAP) results in income for all periods presented. Therefore, we believe it appropriate and more conservative to calculate an Adjusted diluted weighted average shares outstanding utilizing our fully dilutive weighted average shares. As such, as of September 30, 2016 we present a line item that calculates Adjusted diluted Adjusted Net Income per common share. Additionally, as of December 31, 2015 we changed the methodology for calculating Adjusted Net Income by applying a tax rate of 36% to all periods. Accordingly, the prior periods' Adjusted Net Income has been modified for comparability.

The following presents a reconciliation of Net income (loss) (GAAP) to Adjusted Net Income (non-GAAP):

Adjusted EBITDA (Unaudited)

Adjusted EBITDA is a non-GAAP financial measure that we define as net income or loss plus adjustments for deferred income tax expense or benefit, depletion, depreciation and amortization, bad debt expense, impairment expense, non-cash stock-based compensation, accretion of asset retirement obligations, restructuring expenses, gains or losses on derivatives, cash settlements received for matured derivatives, cash settlements on early terminated derivatives, cash premiums paid for derivatives, interest expense, write-off of debt issuance costs, gains or losses on disposal of assets, loss on early redemption of debt, buyout of minimum volume commitment, income from equity method investee and proportionate Adjusted EBITDA of equity method investee. 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 and 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, 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.

As of September 30, 2016, we changed the methodology for calculating Adjusted EBITDA by including adjustments for both accretion of asset retirement obligations and our proportionate share of our equity method investee's Adjusted EBITDA. Accordingly, the prior periods' Adjusted EBITDA has been modified for comparability. 

The following presents a reconciliation of Net income (loss) (GAAP) to Adjusted EBITDA (non-GAAP):

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(1) Proportionate Adjusted EBITDA of Medallion, our equity method investee, is calculated as follows: