×

Laredo Petroleum Announces 2017 First-Quarter Financial and Operating Results

TULSA, OK, May 03, 2017 (GLOBE NEWSWIRE) -- Laredo Petroleum, Inc. (NYSE:LPI) ("Laredo" or "the Company") today announced its 2017 first-quarter results, reporting net income attributable to common stockholders of $68.3 million, or $0.28 per diluted share. Adjusted Net Income, a non-GAAP financial measure, for the first quarter of 2017 was $23.8 million, or $0.10 per adjusted diluted share. Adjusted EBITDA, a non-GAAP financial measure, for the first quarter of 2017 was $107.4 million. Please see supplemental financial information at the end of this news release for reconciliations of non-GAAP financial measures.

2017 First-Quarter Highlights

  • Produced 52,405 barrels of oil equivalent ("BOE") per day, an increase of approximately 13% from the first quarter of 2016
  • Completed 13 horizontal development wells with an average completed lateral length of approximately 9,900 feet and conducted drilling operations on five wells with anticipated lateral lengths between 14,000 and 15,600 feet
  • Recorded unit lease operating expenses ("LOE") of $3.60 per BOE, down approximately 26% from the first-quarter 2016 rate of $4.88 per BOE
  • Recognized approximately $5.8 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 148,834 barrels of oil per day ("BOPD") on average for the quarter, an increase of approximately 79% from the first quarter of 2016

"During the first quarter, Laredo again demonstrated how our early adoption of big data analytics, infrastructure build-out and operational best practices is creating value for our shareholders," commented Randy A. Foutch, Chairman and Chief Executive Officer. "We continue to push the envelope to create more robust workflows with our in-house technology to accelerate learning. Laredo is now progressing our analytical tools beyond the Earth Model to create geocellular reservoir models and combining them with advanced fracture modeling to direct our strategy towards high-density development. Our production corridor strategy is crucial for this type of development. Our infrastructure investments have driven our operating costs to among the lowest in the Midland Basin and are scalable to handle the movement of large volumes of oil, natural gas and water generated by high-density development."

Operational Update

In the first quarter of 2017, Laredo produced 52,405 BOE per day, completing 13 horizontal development wells with an average completed lateral length of approximately 9,900 feet. Flowback on a majority of the completions occurred in a compressed period, as the nine wells comprising the JL McMaster-Bodine package began production at approximately the same time. Production from these wells was concentrated in the last month of the first quarter and is expected to have a positive impact on second-quarter production.

The Company has developed a customized managed flowback procedure that is currently being utilized on all newly completed wells. Implementing this procedure has yielded compelling near-term production results, with wells utilizing managed flowback exhibiting higher total production and oil cuts versus wells not utilizing the procedure. Although wells utilizing Laredo's managed flowback procedure exhibited lower total production in the near term, the deficit was overcome in less than 90 days. Laredo currently estimates that the Company's wells utilizing the customized managed flowback procedure, which has no incremental capital cost, will recognize an increase in net present value of $300,000 to $400,000 per well in the first year of production.

The nine-well JL McMaster-Bodine package, completed in the first quarter of 2017, is indicative of the positive results of the Company's managed flowback procedure. While still early in its production history, the package is currently outperforming the Company's Upper/Middle Wolfcamp three-stream type curve by 26% and outperforming our oil type curve by 38%.

Results of the Company's testing of higher proppant concentrations, as part of its optimized completions, continue to improve. Laredo now has production data from 13 wells completed utilizing 2,400 pounds of proppant per lateral foot. This group of wells is currently outperforming the Company's Upper/Middle Wolfcamp type curve by approximately 40%. Included in this dataset are four wells completed in the first quarter of 2017 that utilized the higher proppant concentration. Additionally, the Company completed a well utilizing 3,300 pounds of proppant per lateral foot. Although it is too early to make a determination of the economic value of proppant concentrations greater than 1,800 pounds per lateral foot, Laredo will continue to monitor production data and expects to conduct additional tests in the second quarter of 2017.

Laredo continues to capitalize on its contiguous acreage base to focus on drilling capital-efficient, long-lateral wells. During the first quarter, the Company successfully completed the drilling of two wells with drilled lateral lengths greater than 14,000 feet and began drilling three wells expected to have drilled lateral lengths greater than 15,000 feet. Laredo expects to continue drilling longer laterals as the Company has definitive data showing no degradation in well performance as lateral lengths exceed 10,000 feet, enabling efficiencies that lower cost per foot and drive higher rates of return.

Laredo continues to utilize its extensive dataset and in-house technology development to enhance shareholder value. The Company used big data concepts to create its proprietary multivariate Earth Model to help isolate production drivers and measure their impact. This has led to significant outperformance of the Company's type curves by wells utilizing this analysis. Laredo is now using this data to create high-resolution geocellular reservoir models and fracture models to guide strategic testing of high-density development. In the second quarter of 2017, the Company will begin a six-well package in the Upper, Middle and Lower Wolfcamp to test the co-development of multiple landing points within the Upper and Middle Wolfcamp formations. The results of this test are anticipated at year-end 2017 and are expected to refine spacing and completion concepts that further optimize Laredo's development plan and enhance the value of its acreage.

In the second quarter of 2017, the Company expects to complete approximately 18 wells with an average completed lateral length of approximately 10,100 feet. The completion count will be impacted by the timing of packages and the nature of completion tests. As the Company tests tighter spacing of perforation clusters and acquires microseismic data of these tests, the flowback timing of these wells can vary versus scheduled timing.

Lease operating expenses again benefited from the Company's investments in field infrastructure and the concentration of drilling around Laredo's production corridors. Total LOE in the first quarter of 2017 decreased approximately 2% from the fourth quarter of 2016. Infrastructure-related savings reduced unit LOE by $0.46 per BOE to $3.60 per BOE in the first quarter of 2017. The Company anticipates unit LOE will continue to benefit from prior infrastructure investments and believes the infrastructure-related savings will grow should costs increase.

In the first quarter of 2017, well costs were in-line with Laredo's expectations of $6.4 million for a 10,000-foot Upper or Middle Wolfcamp well completed with 1,800 pounds per lateral foot of proppant. During the second quarter of 2017, the Company expects to experience upward pressure on the stimulation services segment of well costs. Laredo continues to mitigate a portion of these increases through efficiency gains, procurement initiatives and evaluation of new vendors. Due to the variability of the current commodity price environment and the Company's historical success managing service cost increases, Laredo is not adjusting well cost or budget estimates at this time.

Laredo Midstream Services Update

During the first quarter of 2017, LMS gathered on pipe 73% of the Company's gross operated oil production and 65% of total produced water and generated approximately $5.8 million of total cash benefit for the Company. The Company anticipates the percentage of gross operated oil production and total produced water to be gathered by LMS to increase throughout 2017, contributing to an expected total cash benefit of approximately $28 million during 2017.

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 148,834 BOPD, an increase of approximately 79% from the first quarter of 2016 and up 15% from the fourth quarter of 2016. The system is expected to transport an average of approximately 175,000 BOPD during the second quarter of 2017.

2017 Capital Program

During the first quarter of 2017, Laredo invested approximately $109 million in exploration and development activities. Other expenditures incurred during the quarter included approximately $13 million in bolt-on land acquisitions and lease extensions, approximately $1 million in infrastructure held by LMS and approximately $5 million in capitalized employee-related costs.

Liquidity

At March 31, 2017, the Company had cash and cash equivalents of approximately $30 million and undrawn capacity under the senior secured credit facility of $750 million.

The Company recently amended and restated its senior secured credit facility, which now matures in 2022. The Company's borrowing base increased to $1.0 billion from $815 million. At May 2, 2017, the Company had cash and equivalents of approximately $20 million and undrawn capacity under the senior secured credit facility of $925 million, resulting in total liquidity of approximately $945 million.

Commodity Derivatives

Laredo maintains a disciplined hedging program to reduce the variability in its anticipated cash flow due to fluctuations in commodity prices. At March 31, 2017, the Company had hedges in place for the remaining three quarters of 2017 for 5,163,125 barrels of oil at a weighted-average floor price of $55.82 per barrel. A substantial portion of Laredo's remaining 2017 oil hedges retain the benefit of an increase in the price of oil with hedges covering 2,860,000 barrels structured as collars with a weighted-average ceiling price of $86.00 per barrel and hedges covering 790,625 barrels in the form of puts and thus do not have a ceiling.

The Company also had hedges in place for the remaining three quarters of 2017 for 20,357,500 million British thermal units ("MMBtu") of natural gas at a weighted-average floor price of $2.75 per MMBtu. All natural gas hedges the Company has in place are priced at the WAHA hub. Additionally, Laredo had hedged 333,000 barrels of ethane at $11.24 per barrel and 281,250 barrels of propane at $22.26 per barrel.

At March 31, 2017, for 2018, the Company had hedged 3,458,375 barrels of oil at a weighted-average floor price of $53.71 per barrel and 12,855,500 MMBtu of natural gas at a weighted-average floor price of $2.50 per MMBtu, priced at the WAHA hub. Subsequently, the Company hedged an additional 10,950,000 MMBtu of natural gas for 2018 at a weighted-average floor price of $2.50 per MMBtu, priced at the WAHA hub.

Second-Quarter and Full-Year 2017 Guidance

The Company is reiterating its previously stated anticipated full-year 2017 production growth guidance of at least 15%. The table below reflects the Company’s guidance for the second quarter of 2017:

2Q-2017
Production (MBOE/d) 55 - 58
Product % of total production:
Crude oil 45% - 47%
Natural gas liquids 26% - 27%
Natural gas 27% - 28%
Price Realizations (pre-hedge):
Crude oil (% of WTI) ~88%
Natural gas liquids (% of WTI) ~29%
Natural gas (% of Henry Hub) ~68%
Operating Costs & Expenses:
Lease operating expenses ($/BOE) $3.50 - $4.00
Midstream expenses ($/BOE) $0.20 - $0.30
Production and ad valorem taxes (% of oil, NGL and natural gas revenue) 6.5%
General and administrative expenses:
Cash ($/BOE) $3.00 - $3.50
Non-cash stock-based compensation ($/BOE) $1.75 - $2.00
Depletion, depreciation and amortization ($/BOE) $7.25 - $7.75

Conference Call Details

On Thursday, May 4, 2017, at 7:30 a.m. CT, Laredo will host a conference call to discuss its first-quarter 2017 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 8986853, approximately 10 minutes prior to the scheduled conference time. International participants should dial 253.336.8309, also using conference code 8986853. A telephonic replay will be available approximately two hours after the call on May 4, 2017 through Thursday, May 11, 2017. Participants may access this replay by dialing 855.859.2056, using conference code 8986853.

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 gathering of oil and liquids-rich 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, 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. 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, 2016, 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.

Laredo Petroleum, Inc.
Condensed consolidated statements of operations
Three months ended March 31,
(in thousands, except per share data) 2017 2016
(unaudited)
Revenues:
Oil, NGL and natural gas sales $138,736 $73,142
Midstream service revenues 2,999 1,801
Sales of purchased oil 47,271 31,614
Total revenues 189,006 106,557
Costs and expenses:
Lease operating expenses 16,992 20,518
Production and ad valorem taxes 8,781 6,435
Midstream service expenses 916 609
Costs of purchased oil 50,256 32,946
General and administrative 25,597 19,451
Depletion, depreciation and amortization 34,112 41,478
Impairment expense 161,064
Other operating expenses 1,026 844
Total costs and expenses 137,680 283,345
Operating income (loss) 51,326 (176,788)
Non-operating income (expense):
Gain on derivatives, net 36,671 17,885
Income from equity method investee 3,068 2,298
Interest expense (22,720) (23,705)
Other, net (69) (61)
Non-operating income (expense), net 16,950 (3,583)
Income (loss) before income taxes 68,276 (180,371)
Income tax:
Deferred
Total income tax
Net income (loss) $68,276 $(180,371)
Net income (loss) per common share:
Basic $0.29 $(0.85)
Diluted $0.28 $(0.85)
Weighted-average common shares outstanding:
Basic 238,505 211,560
Diluted 244,379 211,560


Laredo Petroleum, Inc.
Condensed consolidated balance sheets
(in thousands) March 31, 2017 December 31, 2016
Assets: (unaudited) (unaudited)
Current assets $152,629 $154,777
Property and equipment, net 1,401,484 1,366,867
Other noncurrent assets 264,483 260,702
Total assets $1,818,596 $1,782,346
Liabilities and stockholders' equity:
Current liabilities $162,335 $187,945
Long-term debt, net 1,349,591 1,353,909
Other noncurrent liabilities 53,760 59,919
Stockholders' equity 252,910 180,573
Total liabilities and stockholders' equity $1,818,596 $1,782,346


Laredo Petroleum, Inc.
Condensed consolidated statements of cash flows
Three months ended March 31,
(in thousands) 2017 2016
(unaudited)
Cash flows from operating activities:
Net income (loss) $68,276 $(180,371)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization 34,112 41,478
Impairment expense 161,064
Non-cash stock-based compensation, net of amounts capitalized 9,224 3,838
Mark-to-market on derivatives:
Gain on derivatives, net (36,671) (17,885)
Cash settlements received for matured derivatives, net 7,451 65,937
Cash settlements received for early terminations of derivatives, net 80,000
Cash premiums paid for derivatives (2,107) (81,850)
Other, net (762) (6,494)
Cash flows from operations before changes in working capital and other noncurrent liabilities 79,523 65,717
Decrease in working capital (15,695) (9,131)
Decrease in other noncurrent liabilities (44) (69)
Net cash provided by operating activities 63,784 56,517
Cash flows from investing activities:
Capital expenditures:
Oil and natural gas properties (110,542) (105,155)
Midstream service assets (1,731) (1,937)
Other fixed assets (1,203) (630)
Investment in equity method investee (26,660)
Proceeds from dispositions of capital assets, net of selling costs 59,515 218
Net cash used in investing activities (53,961) (134,164)
Cash flows from financing activities:
Borrowings on Senior Secured Credit Facility 50,000 85,000
Payments on Senior Secured Credit Facility (55,000) (25,000)
Other, net (7,143) (1,412)
Net cash (used in) provided by financing activities (12,143) 58,588
Net decrease in cash and cash equivalents (2,320) (19,059)
Cash and cash equivalents, beginning of period 32,672 31,154
Cash and cash equivalents, end of period $30,352 $12,095


Laredo Petroleum, Inc.
Selected operating data
Three months ended March 31,
2017 2016
(unaudited)
Sales volumes:
Oil (MBbl) 2,120 2,006
NGL (MBbl) 1,263 1,066
Natural gas (MMcf) 8,000 6,796
Oil equivalents (MBOE)(1)(2) 4,716 4,204
Average daily sales volumes (BOE/D)(1) 52,405 46,202
% Oil 45% 48%
Average sales prices:
Oil, realized ($/Bbl)(1)(3) $46.91 $27.51
NGL, realized ($/Bbl)(1)(3) $16.49 $8.50
Natural gas, realized ($/Mcf)(1)(3) $2.31 $1.31
Average price, realized ($/BOE)(1)(3) $29.42 $17.40
Oil, hedged ($/Bbl)(1)(4) $49.70 $56.84
NGL, hedged ($/Bbl)(1)(4) $16.04 $8.50
Natural gas, hedged ($/Mcf)(1)(4) $2.31 $2.08
Average price, hedged ($/BOE)(1)(4) $30.55 $32.64
Average costs per BOE sold(1):
Lease operating expenses $3.60 $4.88
Production and ad valorem taxes 1.86 1.53
Midstream service expenses 0.19 0.14
General and administrative:
Cash 3.47 3.72
Non-cash stock-based compensation, net of amounts capitalized 1.96 0.91
Depletion, depreciation and amortization 7.23 9.87
Total $18.31 $21.05

_______________________________________________________________________________

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

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

(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.

(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.

Laredo Petroleum, Inc.
Costs incurred
Costs incurred in the acquisition, exploration and development of oil, NGL and natural gas assets are presented below:
Three months ended March 31,
(in thousands) 2017 2016
(unaudited)
Property acquisition costs:
Evaluated $ $
Unevaluated
Exploration costs 15,543 7,263
Development costs(1) 111,158 81,886
Total costs incurred $126,701 $89,149

_______________________________________________________________________________

(1) Development costs include $0.1 million in asset retirement obligations for each of the three months ended March 31, 2017 and 2016.


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, mark-to-market on derivatives, cash premiums paid for derivatives, impairment expense, gains or losses on disposal of assets, 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.

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, for the three months ended March 31, 2016, our net loss (GAAP) per common share calculation utilizes the same denominator for both basic and diluted net loss per common share. However, our calculation of Adjusted Net Income (non-GAAP) results in income for both periods presented. Therefore, we believe it appropriate and more conservative to calculate an Adjusted diluted weighted-average common shares outstanding utilizing our fully dilutive weighted-average common shares. As such, for each of the three months ending March 31, 2017 and 2016, we present a line item that calculates Adjusted Net Income per Adjusted diluted common share. Accordingly, the prior period's Adjusted Net Income has been modified for comparability.

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

Three months ended March 31,
(in thousands, except for per share data, unaudited) 2017 2016
Net income (loss) $68,276 $(180,371)
Plus:
Mark-to-market on derivatives:
Gain on derivatives, net (36,671) (17,885)
Cash settlements received for matured derivatives, net 7,451 65,937
Cash settlements received for early terminations of derivatives, net 80,000
Cash premiums paid for derivatives (2,107) (81,850)
Impairment expense 161,064
Loss on disposal of assets, net 214 160
Adjusted net income before adjusted income tax expense 37,163 27,055
Adjusted income tax expense (13,379) (9,740)
Adjusted Net Income $23,784 $17,315
Net income (loss) per common share:
Basic $0.29 $(0.85)
Diluted $0.28 $(0.85)
Adjusted Net Income per common share:
Basic $0.10 $0.08
Adjusted diluted $0.10 $0.08
Weighted-average common shares outstanding:
Basic 238,505 211,560
Diluted 244,379 211,560
Adjusted diluted 244,379 213,995

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, impairment expense, non-cash stock-based compensation, net of amounts capitalized, accretion expense, mark-to-market on derivatives, cash premiums paid for derivatives, interest expense, gains or losses on disposal of assets, income or loss from equity method investee, proportionate Adjusted EBITDA of equity method investee 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 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.

During the year ended December 31, 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 period's Adjusted EBITDA has been modified for comparability.

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

Three months ended March 31,
(in thousands, unaudited) 2017 2016
Net income (loss) $68,276 $(180,371)
Plus:
Depletion, depreciation and amortization 34,112 41,478
Impairment expense 161,064
Non-cash stock-based compensation, net of amounts capitalized 9,224 3,838
Accretion expense 928 844
Mark-to-market on derivatives:
Gain on derivatives, net (36,671) (17,885)
Cash settlements received for matured derivatives, net 7,451 65,937
Cash settlements received for early terminations of derivatives, net 80,000
Cash premiums paid for derivatives (2,107) (81,850)
Interest expense 22,720 23,705
Loss on disposal of assets, net 214 160
Income from equity method investee (3,068) (2,298)
Proportionate Adjusted EBITDA of equity method investee(1) 6,365 3,684
Adjusted EBITDA $107,444 $98,306

_______________________________________________________________________________

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

Three months ended March 31,
(in thousands, unaudited) 2017 2016
Income from equity method investee $3,068 $2,298
Adjusted for proportionate share of:
Depreciation and amortization 3,297 1,386
Proportionate Adjusted EBITDA of equity method investee $6,365 $3,684

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

17-5


Source:Laredo Petroleum, Inc.