EX-99.1 2 a050218lpipr.htm EXHIBIT 99.1 Exhibit
EXHIBIT 99.1

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15 West 6th Street, Suite 900 · Tulsa, Oklahoma 74119 · (918) 513-4570 · Fax: (918) 513-4571
www.laredopetro.com

Laredo Petroleum Announces 2018 First-Quarter Financial and Operating Results

TULSA, OK - May 2, 2018 - Laredo Petroleum, Inc. (NYSE: LPI) ("Laredo" or "the Company") today announced its 2018 first-quarter results, reporting net income attributable to common stockholders of $86.5 million, or $0.36 per diluted share. Adjusted Net Income, a non-GAAP financial measure, for the first quarter of 2018 was $57.6 million, or $0.24 per diluted share. Adjusted EBITDA, a non-GAAP financial measure, for the first quarter of 2018 was $143.4 million. Please see supplemental financial information at the end of this news release for reconciliations of non-GAAP financial measures.
2018 First-Quarter Highlights
•
Produced a Company record 63,314 barrels of oil equivalent ("BOE") per day and increased anticipated production growth for full-year 2018 to greater than 12%
•
Reduced unit cash costs to $8.74 per BOE, a decrease of approximately 4% from the first quarter of 2017
•
Increased Adjusted EBITDA to $143.4 million, up 33% from the first quarter of 2017
•
Repurchased 6,727,901 shares of common stock at a weighted-average price of $8.69 per share for $58.5 million under the Company's share repurchase program
"Operational results in the first quarter were in-line with expectations as we overcame delays from adverse weather at the beginning of the quarter," stated Randy A. Foutch, Chairman and Chief Executive Officer. "We completed four more wells than projected, driven by efficiency gains in our completions operations that pulled wells forward from the second quarter. The results our drilling and completions teams were able to accomplish to shorten cycle times significantly improved efficiency during the quarter."
"We are increasing our production expectations for 2018 as our work to optimize contract areas on our contiguous acreage is increasing both the working interest and lateral lengths of our wells. Additionally, the longer-term results from well packages designed to test tighter spacing are encouraging. We are aggressively moving forward with our development utilizing 32 Upper/Middle Wolfcamp wells per drilling spacing unit which, coupled with shorter cycle times and an accelerated pace of drilling, is expected to drive improved capital efficiency. We now anticipate adding a fifth horizontal drilling rig around the end of 2018 or beginning of 2019."

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E&P Update
In the first quarter of 2018, Laredo produced a Company record 63,314 BOE per day, completing 20 gross (20 net) horizontal wells with an average completed lateral length of approximately 9,700 feet. The number of completions in first-quarter 2018 was positively impacted by shortened cycle times, reflecting efficiency improvements related to contracting a second dedicated completions crew and completion design modifications.
Laredo continued to utilize various completion designs during the first quarter with the goal of improving productivity, reducing capital costs and driving improved capital efficiency. Design refinements included lengthening stages, reducing fluid concentrations and utilizing PerfExtra, the Gas Technology Institutes' patented hydraulic fracturing technology. These completion designs were planned as parts of larger well packages wherein the remaining wells were completed with the Company's standard design in order to obtain a direct comparison of the wells' productivity. Well productivity is balanced with the capital savings to assess the value of the completion design modifications. Lengthening stages and reducing fluid concentrations both contributed to cycle time and capital costs reductions. The initial productivity of the wells with reduced fluid concentration has been below expectations, although additional production data will be needed to determine the impact on longer-term capital efficiency. The Company does expect to continue to phase in longer stage lengths and PerfExtra on wells throughout the year, as they are positive for capital efficiency.
Unit lease operating expenses ("LOE") were $3.85 per BOE in the first quarter of 2018, the seventh consecutive quarter of unit LOE less than $4.00 per BOE. Cost pressure and non-recurring well work contributed to the increase from fourth-quarter 2017. The Company's guidance for second-quarter 2018 unit LOE of $3.70 per BOE is expected to be more reflective of unit LOE for the remainder of 2018.
Laredo expects to complete 17 gross horizontal wells (16.5 net) in the second quarter of 2018 with an average completed lateral length of approximately 10,800 feet. Eleven of these wells are being developed as a package and are not expected to begin flowback until the end of second-quarter 2018. The Company is currently operating three horizontal drilling rigs and is in the process of adding a fourth rig at the beginning of the third quarter. Laredo also expects to add a fifth horizontal rig around the end of 2018 or beginning of 2019 as completion efficiency gains and the current commodity price environment drive increasing operating cash flow.
The Company expects average completed lateral length to increase throughout 2018. Laredo's first three 15,000-foot horizontal wells have continued to improve since they were completed in the third quarter of 2017 and their average cumulative production is now performing in-line with the Company's Upper/Middle Wolfcamp type curve, adjusted for their lateral length. Laredo's contiguous acreage currently supports more than 500 land-ready Upper/Middle Wolfcamp locations of at least 15,000 feet.
Positive results from previously drilled co-developed packages support Laredo's transition to a 32 Upper/Middle Wolfcamp wells per drilling spacing unit ("DSU") development plan. The Sugg-A 157/158 five-well package, developed on 32 Upper/Middle Wolfcamp wells per DSU spacing and completed in the second and third quarters of 2017, is performing above type curve after approximately nine months. The nine-well Lane Trust package, developed on 24 Upper/Middle Wolfcamp wells per DSU spacing and completed in the fourth quarter of 2017, is

2

also performing above type curve. Throughout the remainder of 2018, Laredo expects approximately 20 to 25 of its remaining completions in 2018 to be developed on 32 Upper/Middle Wolfcamp wells per DSU spacing.
The Company is increasing its anticipated full-year 2018 total production growth guidance to greater than 12% and reiterating previously-issued oil production growth guidance of greater than 10% as compared to 2017. Quarterly production growth is expected to be uneven as three packages of at least eight wells are scheduled to be brought on production throughout the last seven months of 2018.
Crude Marketing
Laredo crude marketing has focused on achieving the ability to sell crude in multiple markets and protecting the Company's oil pricing from basin differentials. The Company entered into a crude oil purchase agreement with Shell Trading (US) Company ("Shell") effective October 1, 2016 through June 30, 2020 ("the Contract"), for this purpose. The Contract provided a menu of pricing alternatives that enabled Laredo, at the Company's option, to take advantage of Midland market pricing as well as U.S. Gulf Coast market pricing.
As previously reported, on May 3, 2017, Shell sued Laredo, alleging that the Contract did not accurately reflect the compensation to be paid to Shell under one of the pricing options due to a drafting mistake, despite clear language in the Contract to the contrary. Laredo does not believe that there was a drafting mistake. Although the Contract is still the subject of litigation regarding the alleged mistake and other related claims asserted by Shell, as of May 1, 2018, Shell has terminated the Contract and informed Laredo that it will no longer continue to purchase crude oil from Laredo, as well as sell crude oil to Laredo, as it is required to do under the Contract. Laredo believes the termination was improper and the Company intends to vigorously pursue its rights under the terminated Contract and seek all appropriate damages from Shell. The Company continues to believe that Shell's claims are without merit.
Although not reflective of the total damages caused by Shell's wrongful termination, the estimated current net impact to Laredo's crude oil price realization as a result of the Shell breach is the reduction of aggregate second-quarter 2018 forecasted crude oil price realizations from 95% of West Texas Intermediate ("WTI") to 91% of WTI. The Company estimates that approximately 70% of its anticipated crude oil production for the remainder of 2018 is still protected from the Midland basis differential through a combination of 10,000 barrels of oil per day ("BOPD") of Midland-Cushing basis swaps and 10,000 BOPD of Laredo's firm capacity on the Bridgetex pipeline, hedged with Midland-Houston basis swaps, providing Laredo exposure to pricing at the U.S. Gulf Coast market.
Further discussion regarding the litigation will be included in the Company's Quarterly Report on Form 10-Q.
Natural Gas Marketing
The Company, through Laredo Midstream Services, LLC ("LMS"), a wholly-owned subsidiary of Laredo, owns approximately 170 miles of natural gas gathering pipelines. By owning the pipelines that deliver natural gas to processors' systems instead of utilizing gathering infrastructure owned by a processor, Laredo is better able to manage the delivery of its gas for sales. Should a processor be unable to accept the Company's natural gas

3

production due to curtailments, Laredo's owned natural gas gathering system has the ability to shift production to another processor for continued natural gas sales.
In addition to the Company's focus on field-level flow assurance, Laredo makes substantial efforts to protect anticipated cash flows generated from the sales of the Company's produced natural gas. For 2018, the Company has hedged approximately 75% of anticipated natural gas production to protect from a widening Waha basis. For the second quarter of 2018, resulting from a severe widening of the Waha basis, Laredo anticipates the Company's realized price for natural gas will be approximately 36% of Henry Hub. If the Company's natural gas hedges and basis swaps were included in realized pricing, the anticipated realized price would rise to 62% of Henry Hub.
2018 Capital Program
During the first quarter of 2018, Laredo invested approximately $140 million in drilling and completion activities. Other expenditures incurred during the quarter included approximately $3 million in bolt-on land acquisitions, lease extensions and data, approximately $8 million in infrastructure, including LMS investments, and approximately $10 million in other capitalized costs.
The Company's expected working interest and lateral length for wells completed in 2018 has increased from original budget expectations to approximately 95% and 10,600 feet, respectively. Additionally, delayed implementation of in-basin sand is impacting well costs. Including these new expectations, drilling and completion capital for 2018 is expected to increase $30 million to $500 million. Other capital expenditures are expected to remain unchanged at $85 million, bringing total annual capital expenditures to $585 million.
Liquidity
At March 31, 2018, the Company had cash and cash equivalents of approximately $56 million and undrawn capacity under the senior secured credit facility of $945 million, resulting in total liquidity of approximately $1.0 billion.
On April 19, 2018, in connection with the semi-annual redetermination of the Company's senior secured credit facility, lenders increased the Company's borrowing base to $1.3 billion and Laredo increased its elected commitment to $1.2 billion. The pricing grid for the facility was reduced by 75 basis points for drawn amounts at all utilization breakpoints.
At May 1, 2018, the Company had cash and equivalents of approximately $81 million and available capacity under the senior secured credit facility of $1.09 billion, resulting in total available liquidity of approximately $1.17 billion.
Commodity Derivatives
Laredo maintains a disciplined hedging program to reduce the variability in its anticipated cash flow due to fluctuations in commodity prices. The Company utilizes a combination of puts, swaps and collars, entering into contracts solely with banks that are part of its senior secured credit facility. Laredo currently has hedges in place for approximately 90% of anticipated oil production in 2018 and has oil hedges through 2020. Laredo has also entered into NGL and natural gas hedges through 2018 and basis hedges through 2020. Details of the Company's hedge

4

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 2018 total production growth guidance to greater than 12% and reiterating previously issued oil production growth guidance of greater than 10% as compared to 2017. The table below reflects the Company's guidance for the second quarter of 2018.
 
2Q-2018E
Total production (MBOE/d)
64.0
Oil production (MBO/d)
27.4
 
 
Price Realizations (pre-hedge):
 
      Crude oil (% of WTI)
91%
      Natural gas liquids (% of WTI)
28%
      Natural gas (% of Henry Hub)
36%
 
 
Operating Costs & Expenses:
 
      Lease operating expenses ($/BOE)
 $3.70
      Midstream expenses ($/BOE)
 $0.15
      Production and ad valorem taxes (% of oil, NGL and natural gas revenue)
6.25%
      General and administrative expenses:
 
           Cash ($/BOE)
 $2.70
           Non-cash stock-based compensation ($/BOE)
 $1.85
      Depletion, depreciation and amortization ($/BOE)
 $8.00
Conference Call Details
On Thursday, May 3, 2018, at 7:30 a.m. CT, Laredo will host a conference call to discuss its first-quarter 2018 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 3698623, approximately 10 minutes prior to the scheduled conference time. International participants should dial 253.336.8309, also using conference code 3698623. A telephonic replay will be available approximately two hours after the call on May 3, 2018 through Thursday, May 10, 2018. Participants may access this replay by dialing 855.859.2056, using conference code 3698623.
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.

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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, the increase in service costs, hedging activities, possible impacts of pending or potential 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, 2017, 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, drilling costs 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.

6

Laredo Petroleum, Inc.
Condensed consolidated statements of operations
 
 
Three months ended March 31,
(in thousands, except per share data)
 
2018
 
2017
 
 
(unaudited)
Revenues:
 
 
 
 
Oil, NGL and natural gas sales
 
$
197,434

 
$
138,736

Midstream service revenues
 
2,359

 
2,999

Sales of purchased oil
 
59,903

 
47,271

Total revenues
 
259,696

 
189,006

Costs and expenses:
 
 
 
 
Lease operating expenses
 
21,951

 
16,992

Production and ad valorem taxes
 
11,812

 
8,781

Midstream service expenses
 
693

 
916

Costs of purchased oil
 
60,664

 
50,256

General and administrative
 
24,725

 
25,597

Depletion, depreciation and amortization
 
45,553

 
34,112

Other operating expenses
 
1,106

 
1,026

Total costs and expenses
 
166,504

 
137,680

Operating income
 
93,192

 
51,326

Non-operating income (expense):
 
 
 
 
Gain on derivatives, net
 
9,010

 
36,671

Income from equity method investee(1)
 
—

 
3,068

Interest expense
 
(13,518
)
 
(22,720
)
Other, net
 
(2,164
)
 
(69
)
Non-operating income (expense), net
 
(6,672
)
 
16,950

Income before income taxes
 
86,520

 
68,276

Income tax:
 
 
 
 
Deferred
 
—

 
—

Total income tax
 
—

 
—

Net income
 
$
86,520

 
$
68,276

Net income per common share:
 
 
 
 
Basic
 
$
0.36

 
$
0.29

Diluted
 
$
0.36

 
$
0.28

Weighted-average common shares outstanding:
 
 
 
 
Basic
 
238,228

 
238,505

Diluted
 
239,319

 
244,379

____________________________________________________________
(1)
On October 30, 2017, LMS, together with Medallion Midstream Holdings, LLC, which is owned and controlled by an affiliate of the third-party interest holder, The Energy & Minerals Group, completed the sale of 100% of the ownership interests in Medallion Gathering & Processing, LLC, a Texas limited liability company formed on October 12, 2012, which, together with its wholly-owned subsidiaries (collectively, "Medallion"), to an affiliate of Global Infrastructure Partners ("GIP"), for cash consideration of $1.825 billion (the "Medallion Sale"). LMS' net cash proceeds for its 49% ownership interest in Medallion in 2017 were $829.6 million, before post-closing adjustments and taxes, but after deduction of its proportionate share of fees and other expenses associated with the Medallion Sale. On February 1, 2018, closing adjustments were finalized and LMS received additional net cash of $1.7 million for total net cash proceeds before taxes of $831.3 million. The Medallion Sale closed pursuant to the membership interest purchase and sale agreement, which provides for potential post-closing additional cash consideration that is structured based on GIP's realized profit at exit. There can be no assurance as to when and whether the additional consideration will be paid.





7

Laredo Petroleum, Inc.
Condensed consolidated balance sheets

(in thousands)
 
March 31, 2018
 
December 31, 2017
 
 
(unaudited)
Assets:
 

 
 
Current assets
 
$
185,193

 
$
235,382

Property and equipment, net
 
1,882,249

 
1,768,385

Noncurrent assets
 
20,089

 
19,522

Total assets
 
$
2,087,531

 
$
2,023,289

Liabilities and stockholders' equity:
 
 
 
 
Current liabilities
 
$
239,666

 
$
277,419

Long-term debt, net
 
847,300

 
791,855

Noncurrent liabilities
 
58,735

 
188,436

Stockholders' equity
 
941,830

 
765,579

Total liabilities and stockholders' equity
 
$
2,087,531

 
$
2,023,289






8

Laredo Petroleum, Inc.
Condensed consolidated statements of cash flows

 
 
Three months ended March 31,
(in thousands)
 
2018
 
2017
 
 
(unaudited)
Cash flows from operating activities:
 
 

 
 

Net income
 
$
86,520

 
$
68,276

Adjustments to reconcile net income to net cash provided by operating activities:
 
 

 
 
Depletion, depreciation and amortization
 
45,553

 
34,112

Non-cash stock-based compensation, net
 
9,339

 
9,224

Mark-to-market on derivatives:
 
 
 
 
Gain on derivatives, net
 
(9,010
)
 
(36,671
)
Settlements (paid) received for matured derivatives, net
 
(2,236
)
 
7,451

Premiums paid for derivatives
 
(4,024
)
 
(2,107
)
Other, net(1)
 
5,308

 
(762
)
Cash flows from operations before changes in assets and liabilities
 
131,450

 
79,523

Decrease (increase) in current assets and liabilities, net
 
15,495

 
(15,695
)
Increase in other noncurrent assets and liabilities, net
 
(474
)
 
(44
)
Net cash provided by operating activities
 
146,471

 
63,784

Cash flows from investing activities:
 
 
 
 
Capital expenditures:
 
 
 
 
Oil and natural gas properties
 
(195,025
)
 
(110,542
)
Midstream service assets
 
(3,362
)
 
(1,731
)
Other fixed assets
 
(3,963
)
 
(1,203
)
Proceeds from disposition of equity method investee, net of selling costs(1)
 
1,655

 
—

Proceeds from dispositions of capital assets, net of selling costs
 
1,021

 
59,515

Net cash used in investing activities
 
(199,674
)
 
(53,961
)
Cash flows from financing activities:
 
 
 
 
Borrowings on Senior Secured Credit Facility
 
55,000

 
50,000

Payments on Senior Secured Credit Facility
 
—

 
(55,000
)
Share repurchases
 
(53,714
)
 
—

Other, net
 
(4,353
)
 
(7,143
)
Net cash used in financing activities
 
(3,067
)
 
(12,143
)
Net decrease in cash and cash equivalents
 
(56,270
)
 
(2,320
)
Cash and cash equivalents, beginning of period
 
112,159

 
32,672

Cash and cash equivalents, end of period
 
$
55,889

 
$
30,352

_______________________________________________________________________________
(1)
See footnote 1 to the condensed consolidated statements of operations.


9

Laredo Petroleum, Inc.
Selected operating data

 
 
Three months ended March 31,
 
 
2018
 
2017
 
 
(unaudited)
Sales volumes:
 
 
 
 
Oil (MBbl)
 
2,439

 
2,120

NGL (MBbl)
 
1,563

 
1,263

Natural gas (MMcf)
 
10,173

 
8,000

Oil equivalents (MBOE)(1)(2)
 
5,698

 
4,716

Average daily sales volumes (BOE/D)(2)
 
63,314

 
52,405

% Oil(2)
 
43
%
 
45
%
Average sales prices(2):
 
 
 
 
Oil, realized ($/Bbl)(3)
 
$
61.87

 
$
46.91

NGL, realized ($/Bbl)(3)
 
$
18.14

 
$
16.49

Natural gas, realized ($/Mcf)(3)
 
$
1.79

 
$
2.31

Average price, realized ($/BOE)(3)
 
$
34.65

 
$
29.42

Oil, hedged ($/Bbl)(4)
 
$
58.53

 
$
49.70

NGL, hedged ($/Bbl)(4)
 
$
18.11

 
$
16.04

Natural gas, hedged ($/Mcf)(4)
 
$
1.85

 
$
2.31

Average price, hedged ($/BOE)(4)
 
$
33.34

 
$
30.55

Average costs per BOE sold(2):
 
 
 
 
Lease operating expenses
 
$
3.85

 
$
3.60

Production and ad valorem taxes
 
2.07

 
1.86

Midstream service expenses
 
0.12

 
0.19

General and administrative:
 
 
 
 
Cash
 
2.70

 
3.47

Non-cash stock-based compensation, net
 
1.64

 
1.96

Depletion, depreciation and amortization
 
7.99

 
7.23

Total costs and expenses
 
$
18.37

 
$
18.31

Cash margins per BOE sold(2):
 
 
 
 
Realized
 
$
25.91

 
$
20.30

Hedged
 
$
24.60

 
$
21.43

_______________________________________________________________________________
(1)
BOE is calculated using a conversion rate of six Mcf per one Bbl.
(2)
The numbers 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.
(4)
Hedged prices reflect the after-effects 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.

10

Laredo Petroleum, Inc.
Costs incurred

The following table presents costs incurred in the acquisition, exploration and development of oil and natural gas properties:
 
 
Three months ended March 31,
(in thousands)
 
2018
 
2017
 
 
(unaudited)
Property acquisition costs:
 
 
 
 
Evaluated
 
$
—

 
$
—

Unevaluated
 
—

 
—

Exploration costs
 
6,137

 
15,543

Development costs
 
149,038

 
111,158

Total costs incurred
 
$
155,175

 
$
126,701
































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Laredo Petroleum, Inc.
Supplemental reconciliations 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 flows from operating activities. 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.
Adjusted Net Income
Adjusted Net Income is a non-GAAP financial measure we use to evaluate performance, prior to income tax expense or benefit, mark-to-market on derivatives, premiums paid for derivatives, 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.


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The following table presents a reconciliation of income before income taxes (GAAP) to Adjusted Net Income (non-GAAP):
 
 
Three months ended March 31,
(in thousands, except per share data)
 
2018
 
2017
 
 
(unaudited)
Income before income taxes
 
$
86,520

 
$
68,276

Plus:
 
 
 
 
Mark-to-market on derivatives:
 
 
 
 
Gain on derivatives, net
 
(9,010
)
 
(36,671
)
Settlements (paid) received for matured derivatives, net
 
(2,236
)
 
7,451

Premiums paid for derivatives
 
(4,024
)
 
(2,107
)
Loss on disposal of assets, net
 
2,617

 
214

Adjusted income before adjusted income tax expense
 
73,867


37,163

Adjusted income tax expense(1)
 
(16,251
)

(13,379
)
Adjusted Net Income
 
$
57,616


$
23,784

Net income per common share:
 
 
 
 
Basic
 
$
0.36

 
$
0.29

Diluted
 
$
0.36

 
$
0.28

Adjusted Net Income per common share:
 
 
 
 
Basic
 
$
0.24


$
0.10

Diluted
 
$
0.24

 
$
0.10

Weighted-average common shares outstanding:
 
 
 
 
Basic
 
238,228

 
238,505

Diluted
 
239,319

 
244,379

_______________________________________________________________________________
(1)
Adjusted income tax expense is calculated by applying a statutory tax rate of 22% for the three months ended March 31, 2018, in response to recent changes in the tax code, and 36% for the three months ended March 31, 2017.
Adjusted EBITDA
Adjusted EBITDA is a non-GAAP financial measure that we define as net income or loss plus adjustments for 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, 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, 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.

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The following table presents a reconciliation of net income (GAAP) to Adjusted EBITDA (non-GAAP):
 
 
Three months ended March 31,
(in thousands)
 
2018
 
2017
 
 
(unaudited)
Net income
 
$
86,520

 
$
68,276

Plus:
 
 
 
 
Depletion, depreciation and amortization
 
45,553

 
34,112

Non-cash stock-based compensation, net
 
9,339

 
9,224

Accretion expense
 
1,106

 
928

Mark-to-market on derivatives:
 
 
 
 
Gain on derivatives, net
 
(9,010
)
 
(36,671
)
Settlements (paid) received for matured derivatives, net
 
(2,236
)
 
7,451

Premiums paid for derivatives
 
(4,024
)
 
(2,107
)
Interest expense
 
13,518

 
22,720

Loss on disposal of assets, net
 
2,617

 
214

Income from equity method investee(1)
 
—

 
(3,068
)
Proportionate Adjusted EBITDA of equity method investee(1)(2)
 
—

 
6,365

Adjusted EBITDA
 
$
143,383

 
$
107,444

_______________________________________________________________________________
(1)
See footnote 1 to the condensed consolidated statements of operations.
(2)
Proportionate Adjusted EBITDA of Medallion, our equity method investee until its sale on October 30, 2017, is calculated as follows:
 
 
Three months ended March 31,
(in thousands)
 
2018
 
2017
 
 
(unaudited)
Income from equity method investee
 
$
—

 
$
3,068

Adjusted for proportionate share of depreciation and amortization
 
—

 
3,297

Proportionate Adjusted EBITDA of equity method investee
 
$
—

 
$
6,365

# # #

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

                
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