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 Fourth-Quarter and Full-Year 2019 Financial and Operating Results
TULSA, OK - February 12, 2020 - Laredo Petroleum, Inc. (NYSE: LPI) ("Laredo" or "the Company") today announced its fourth-quarter and full-year 2019 results. For the fourth quarter of 2019, the Company reported a net loss attributable to common stockholders of $241.7 million, or $1.04 per diluted share, which includes a non-cash full cost ceiling impairment charge of $222.7 million. Adjusted Net Income, a non-GAAP financial measure, for the fourth quarter of 2019 was $39.7 million, or $0.17 per adjusted diluted share. Adjusted EBITDA, a non-GAAP financial measure, for the fourth quarter of 2019 was $137.9 million.
For full-year 2019, the Company reported a net loss attributable to common stockholders of $342.5 million, or $1.48 per diluted share, which includes a non-cash full cost ceiling impairment charge of $620.6 million. Adjusted Net Income for full-year 2019 was $172.0 million, or $0.74 per adjusted diluted share and Adjusted EBITDA was $560.2 million.
Please see supplemental financial information at the end of this news release for reconciliations of non-GAAP financial measures, including a calculation of Adjusted EBITDA, Adjusted Net Income and Free Cash Flow.
2019 Full-Year Highlights
Generated $475.1 million of net cash provided by operating activities and $59.7 million of Free Cash Flow in 2019 as the Company reduced capital expenditures by 25% from full-year 2018
Executed two accretive acquisitions of high-margin, oily inventory at valuations significantly below historic averages while maintaining a competitive leverage ratio
Produced 28,429 barrels of oil per day ("BOPD") and 80,883 barrels of oil equivalent ("BOE") per day, increases of 2% and 19%, respectively, from full-year 2018
Grew total proved reserves by 55 million BOE and proved oil reserves by 17 million barrels, increases of 23% and 27%, respectively, versus year-end 2018
Drove well costs down to $6.6 million for a 10,000-foot lateral with the Company's standard completion design, a decrease from $7.7 million at year-end 2018
Reduced controllable cash costs of combined unit lease operating expenses ("LOE") and unit cash general and administrative expenses ("G&A") to $4.65 per BOE, a 23% decrease from full-year 2018 results of $6.07 per BOE

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Received net cash of $48.7 million on settlements of derivatives, as the Company's hedges mitigated the impact of commodity price declines
"During 2019, we successfully completed our transition to a returns-focused, free-cash-flow-oriented strategy," stated Jason Pigott, President and Chief Executive Officer. "We substantially improved well productivity, aligned staffing with our moderated development plan and continued to drive down both our well costs and operational expenses. Our strong performance in all facets of the business drove improved capital efficiency and Free Cash Flow generation of approximately $60 million for full-year 2019."
"We leveraged our strengths to complete two accretive acquisitions in oilier areas of the Midland Basin," continued Mr. Pigott. "By deploying our proven operational expertise on acreage with higher oil content, we expect to further improve margins and capital efficiency and drive our oil mix above 40% by 2022. Our development program over the next three years is designed to maintain production levels, generate positive Projected Free Cash Flow at $50 per barrel and deliver more than $100 million in Projected Free Cash Flow at $55 per barrel."
"Financially, we are well positioned to continue delivering on our returns-focused strategy. In January of 2020, we opportunistically refinanced our senior unsecured notes, extending our maturities to 2025 and 2028. For 2020, we have hedged a substantial portion of our expected production at prices well above current levels. Laredo is committed to maintaining its financial strength, improving inventory quality and utilizing Free Cash Flow to reduce debt."
E&P Update
During the fourth quarter of 2019, Laredo completed 15 gross (13.1 net) horizontal wells, all on the Company's wider spacing development plan, with an average completed lateral length of 9,900 feet. Drilling and completion cost incurred of $97 million was in-line with expectations, even with one additional completion, as the Company achieved performance records for both feet drilled and completed feet per day.
In the fourth quarter of 2019, the Company exceeded both oil and total production expectations for the fourth consecutive quarter. Oil production of 27,296 BOPD beat guidance by 5% and total production of 83,968 BOE per day beat guidance by 10%. The primary driver of oil production exceeding expectations during the quarter was the outperformance of the nine-well Sugg/Von Gonten package. This package is currently exceeding the Company's Upper/Middle Wolfcamp oil type curve by 39%.
In the first quarter of 2020, Laredo expects to complete 28 gross (27.7 net) widely-spaced horizontal wells with an average completed lateral length of 8,500 feet. All anticipated first-quarter 2020 completions are on the Company's established acreage in Reagan and Glasscock counties. The Company is currently operating two completion crews and expects to reduce activity to one completion crew by the end of March 2020 as completion activities transition to the newly acquired acreage in Howard and Glasscock counties in the second quarter of 2020.


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Howard County Update
Laredo's transition to its recently acquired Howard County position is moving forward as planned. Two of the Company's four drilling rigs have been deployed to Howard County and a third is expected early in March 2020. The first well of Laredo's first 15-well package in Howard County has been successfully drilled and completion operations are expected to commence on the full package during the second quarter of 2020. Additionally, the Company is in negotiations with multiple third-party providers of oil, natural gas and water infrastructure services and does not expect costs for these services to be significantly different from those on the Company's established acreage base.
In early-February 2020, Laredo executed a bolt-on transaction to its tier-one Howard County position, adding 1,100 net acres for $22.5 million. The acquisition increases the Company's working interest on its operated acreage from 83% to 96%, bringing Laredo's Howard County leasehold to 8,380 net acres (99% operated). The transaction increases the Company's operated inventory in Howard County to 130 gross (124 net) primary locations in the Lower Spraberry, Upper Wolfcamp and Middle Wolfcamp formations.
2019 Capital Program
During the fourth quarter of 2019, excluding non-budgeted acquisitions, total costs incurred were $107 million, comprised of $97 million in drilling and completions activities, $2 million in land and data related costs, $2 million in infrastructure, including Laredo Midstream Services investments, and $6 million in other capitalized costs.
Total costs incurred of $482 million for full-year 2019, excluding non-budgeted acquisitions, was below the Company's $490 million capital budget. For full-year 2019, Laredo delivered approximately $60 million in Free Cash Flow, excluding non-budgeted acquisitions.
Commodity Derivatives
For full-year 2020, the Company has hedged 9.6 million barrels of oil, including 7.2 million barrels at $59.50 WTI and 2.4 million barrels at $63.07 Brent, and 23.8 million MMBtu of natural gas at $2.72 per MMBtu Henry Hub. Combined, Laredo's commodity derivatives are expected to generate $152 million of positive cash flow at $50 per barrel WTI and $2.25 per MMBtu Henry Hub.
Liquidity
At December 31, 2019, the Company had outstanding borrowings of $375 million on its $1.0 billion senior secured credit facility, resulting in available capacity, after the reduction for outstanding letters of credit, of $610 million. Including cash and cash equivalents of $41 million, total liquidity was $651 million.
In January 2020, Laredo issued $1.0 billion of new senior unsecured notes with the net proceeds to be used to redeem its existing $800 million of outstanding senior unsecured notes and to partially repay its senior secured credit facility. To date, the Company has redeemed $749.4 million of the existing notes and has issued call notices for the remaining $50.6 million. In conjunction with the closing of the notes issuance, the Company's borrowing base under its senior secured credit facility was reduced to approximately $950 million.

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At
February 11, 2020
, the Company had outstanding borrowings of $275 million on its senior secured credit facility, resulting in available capacity, after reductions for outstanding letters of credit, of $660 million. Including cash and cash equivalents of $67 million, net of expected cash to be used to redeem the remaining March 2023 Notes, total liquidity was $727 million.
First-Quarter 2020 Guidance
 
1Q-2020E
Total production (MBOE per day)
81.2 - 81.7
Oil production (MBOPD)
26.8 - 27.3
 
 
Average sales price realizations (excluding derivatives):
 
Oil (% of WTI)
100%
NGL (% of WTI)
14%
Natural gas (% of Henry Hub)
13%
 
 
Other ($ MM):
 
   Net income / (expense) of purchased crude oil
($4.0)
   Net midstream income / (expense)
$1.5
 
 
Selected average costs & expenses:
 
Lease operating expenses ($/BOE)
$3.00
Production and ad valorem taxes (% of oil, NGL and natural gas revenues)
6.50%
Transportation and marketing expenses ($/BOE)
$2.15
General and administrative:
 
Cash ($/BOE)
$1.60
Non-cash stock-based compensation, net ($/BOE)
$0.55
Depletion, depreciation and amortization ($/BOE)
$9.00
Conference Call Details
On Thursday, February 13, 2020, at 7:30 a.m. CT, Laredo will host a conference call to discuss its fourth-quarter and full-year 2019 financial and operating results and management's outlook, the content of which is not part of this earnings release. A slide presentation providing summary financial and statistical information that will be discussed on the call will be posted to the Company's website and available for review. The Company invites interested parties to listen to the call via the Company's website at www.laredopetro.com, under the tab for "Investor Relations." Portfolio managers and analysts who would like to participate on the call should dial 877.930.8286 (international dial-in 253.336.8309), using conference code 2388743, 10 minutes prior to the scheduled conference time. A telephonic replay will be available two hours after the call on February 13, 2020 through Thursday, February 20, 2020. Participants may access this replay by dialing 855.859.2056, using conference code 2388743.
About Laredo
Laredo Petroleum, Inc. is an independent energy company with headquarters in Tulsa, Oklahoma. Laredo's business strategy is focused on the acquisition, exploration and development of oil and natural gas properties, primarily in the Permian Basin of West Texas.

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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, indicates, enables, transforms, estimates or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. This press release and any accompanying disclosures may include or reference certain forward-looking, non-GAAP financial measures, such as free cash flow, and certain related estimates regarding future performance, results and financial position. The forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. General risks relating to Laredo include, but are not limited to, the decline in prices of oil, natural gas liquids and natural gas and the related impact to financial statements as a result of asset impairments and revisions to reserve estimates, long-term performance of wells, drilling and operating risks, the increase in service and supply costs, tariffs on steel, pipeline transportation constraints in the Permian Basin, hedging activities, possible impacts of litigation and regulations and other factors, including those and other risks described in its Annual Report on Form 10-K for the year ended December 31, 2018, and those set forth from time to time in other filings with the Securities and Exchange Commission ("SEC") including, but not limited to, its Annual Report on Form 10-K for the year ended December 31, 2019, to be filed with the 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. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.
The SEC generally permits oil and natural gas companies, in filings made with the SEC, to disclose proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions and certain probable and possible reserves that meet the SEC's definitions for such terms. In this press release and the conference call, the Company may use the terms "resource potential" and "estimated ultimate recovery," "type curve" 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 discovered through exploratory drilling or recovered with additional drilling or recovery techniques. “Resource potential” is used by the Company to refer to the estimated quantities of hydrocarbons that may be added to proved reserves, largely from a specified resource play potentially supporting numerous drilling locations. A "resource play" is a term used by the Company to describe an accumulation of hydrocarbons known to exist over a large areal expanse and/or thick vertical section potentially supporting numerous drilling locations, which, when compared to a conventional play, typically has a lower geological and/or commercial development risk. EURs are based on the Company's previous operating experience in a given area and publicly available information relating to the operations of producers who are conducting operations in these areas. Unbooked resource potential or EURs do not constitute reserves within the meaning of the Society of Petroleum Engineer's Petroleum Resource Management System or SEC rules and do not include any proved reserves. Actual quantities of reserves that may be ultimately recovered from the Company's interests may differ substantially from those presented herein. Factors affecting ultimate recovery include the scope of the Company's ongoing drilling program, which will be directly affected by the availability of capital, decreases in oil, natural gas liquids and natural gas prices, well spacing, drilling and production costs, availability and cost of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals, negative revisions to reserve estimates and other factors as well as actual drilling results, including geological and mechanical factors affecting recovery rates. EURs from reserves may change significantly as development of the

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Company's core assets provides additional data. In addition, our production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases. "Type curve" refers to a production profile of a well, or a particular category of wells, for a specific play and/or area. In addition, the Company’s production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases. The "standardized measure" of discounted future new cash flows is calculated in accordance with SEC regulations and a discount rate of 10%. The actual results may vary considerably and should not be considered to represent the fair market value of the Company’s proved reserves.
Unless otherwise specified, references to "average sales price" refer to average sales price excluding the effects of our derivative transactions. All amounts, dollars and percentages presented in this press release are rounded and therefore approximate.


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Laredo Petroleum, Inc.
Selected operating data
 
 
Three months ended December 31,
 
Year ended December 31, 2019
 
 
2019
 
2018
 
2019
 
2018
 
 
(unaudited)
 
(unaudited)
Sales volumes:
 
 
 
 
 
 
 
 
Oil (MBbl)
 
2,511

 
2,571

 
10,376

 
10,175

NGL (MBbl)
 
2,475

 
1,931

 
9,118

 
7,259

Natural gas (MMcf)
 
16,438

 
11,983

 
60,169

 
44,680

Oil equivalents (MBOE)(1)(2)
 
7,725

 
6,500

 
29,522

 
24,881

Average daily oil equivalent sales volumes (BOE/D)(2)
 
83,968

 
70,653

 
80,883

 
68,168

Average daily oil sales volumes (Bbl/D)(2)
 
27,296

 
27,949

 
28,429

 
27,878

Average sales prices(2):
 
 
 
 
 
 
 
 
Oil ($/Bbl)(3)
 
$
56.55

 
$
52.59

 
$
55.21

 
$
59.48

NGL ($/Bbl)(3)
 
$
10.26

 
$
17.53

 
$
11.00

 
$
20.64

Natural gas ($/Mcf)(3)
 
$
0.74

 
$
0.63

 
$
0.55

 
$
1.20

Average sales price ($/BOE)(3)
 
$
23.24

 
$
27.18

 
$
23.93

 
$
32.50

Oil, with commodity derivatives ($/Bbl)(4)
 
$
56.79

 
$
49.55

 
$
54.37

 
$
55.49

NGL, with commodity derivatives ($/Bbl)(4)
 
$
13.02

 
$
17.47

 
$
13.61

 
$
20.03

Natural gas, with commodity derivatives ($/Mcf)(4)
 
$
0.94

 
$
1.74

 
$
1.05

 
$
1.77

Average sales price, with commodity derivatives ($/BOE)(4)
 
$
24.62

 
$
28.01

 
$
25.45

 
$
31.72

Average selected costs and expenses per BOE sold(2):
 
 
 
 
 
 
 
 
Lease operating expenses
 
$
2.84

 
$
3.51

 
$
3.08

 
$
3.67

Production and ad valorem taxes
 
1.43

 
1.73

 
1.38

 
1.99

Transportation and marketing expenses
 
1.32

 
0.79

 
0.86

 
0.47

Midstream service expenses
 
0.14

 
0.16

 
0.15

 
0.12

General and administrative:
 
 
 
 
 
 
 
 
Cash
 
1.33

 
2.08

 
1.57

 
2.40

Non-cash stock-based compensation, net(5) 
 
0.39

 
1.18

 
0.28

 
1.46

Depletion, depreciation and amortization
 
8.78

 
9.29

 
9.00

 
8.55

Total selected costs and expenses
 
$
16.23

 
$
18.74

 
$
16.32

 
$
18.66

Average cash margins per BOE sold(2)(6):
 
 
 
 
 
 
 
 
Without derivatives
 
$
16.18

 
$
18.91

 
$
16.89

 
$
23.85

With commodity derivatives
 
$
17.56

 
$
19.74

 
$
18.41

 
$
23.07

_______________________________________________________________________________
(1)
BOE is calculated using a conversion rate of six Mcf per one Bbl.
(2)
The numbers presented are based on actual amounts and are not calculated using the rounded numbers presented in the table above.
(3)
Price reflects the average of actual sales prices received when control passes to the purchaser/customer adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the delivery point.
(4)
Price reflects the after-effects of our commodity derivative transactions on our average sales prices. Our calculation of such after-effects includes settlements of matured commodity derivatives during the respective periods in accordance with GAAP and an adjustment to reflect premiums incurred previously or upon settlement that are attributable to commodity derivatives that settled during the respective periods.
(5)
For the year ended December 31, 2019, non-cash stock-based compensation, net, excluding forfeitures related to our organizational restructuring, on a per BOE sold basis was $0.66.
(6)
For each period presented, on a per BOE sold basis, average cash margin is calculated as average sales price less (i) lease operating expenses, (ii) production and ad valorem taxes, (iii) transportation and marketing expenses, (iv) midstream service expenses and (v) cash general and administrative.

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Laredo Petroleum, Inc.
Condensed consolidated statements of operations
 
 
Three months ended December 31,

Year ended December 31, 2019
 
 
2019

2018

2019

2018
 
 
(unaudited)
 
(unaudited)
Revenues:
 
 
 
 
 
 

 
 

Oil, NGL and natural gas sales
 
$
179,558

 
$
176,671

 
$
706,548

 
$
808,530

Midstream service revenues
 
3,356

 
2,397

 
11,928

 
8,987

Sales of purchased oil
 
35,208

 
36,219

 
118,805

 
288,258

Total revenues
 
218,122

 
215,287

 
837,281

 
1,105,775

Costs and expenses:
 
 
 
 
 
 
 
 
Lease operating expenses
 
21,948

 
22,823

 
90,786

 
91,289

Production and ad valorem taxes
 
11,080

 
11,225

 
40,712

 
49,457

Transportation and marketing expenses
 
10,164

 
5,134

 
25,397

 
11,704

Midstream service expenses
 
1,085

 
1,048

 
4,486

 
2,872

Costs of purchased oil
 
39,034

 
36,222

 
122,638

 
288,674

General and administrative
 
13,302

 
21,182

 
54,729

 
96,138

Organizational restructuring expenses
 

 

 
16,371

 

Depletion, depreciation and amortization
 
67,846

 
60,399

 
265,746

 
212,677

Impairment expense
 
222,999

 

 
620,889

 

Other operating expenses
 
1,041

 
1,131

 
4,118

 
4,472

Total costs and expenses
 
388,499

 
159,164

 
1,245,872

 
757,283

Operating income (loss)
 
(170,377
)
 
56,123

 
(408,591
)
 
348,492

Non-operating income (expense):
 
 
 
 
 
 
 
 
Gain (loss) on derivatives, net
 
(57,562
)
 
112,195

 
79,151

 
42,984

Interest expense
 
(15,044
)
 
(15,117
)
 
(61,547
)
 
(57,904
)
Litigation settlement
 

 

 
42,500

 

Other, net
 
(514
)
 
(766
)
 
3,440

 
(4,728
)
Total non-operating income (expense), net
 
(73,120
)
 
96,312

 
63,544

 
(19,648
)
Income (loss) before income taxes
 
(243,497
)
 
152,435

 
(345,047
)
 
328,844

Income tax benefit (expense):
 
 
 
 
 
 
 
 
Current
 

 
426

 

 
807

Deferred
 
1,776

 
(3,288
)
 
2,588

 
(5,056
)
Total income tax benefit (expense)
 
1,776

 
(2,862
)
 
2,588

 
(4,249
)
Net income (loss)
 
$
(241,721
)
 
$
149,573

 
$
(342,459
)
 
$
324,595

Net income (loss) per common share:
 
 
 
 
 
 

 
 
Basic
 
$
(1.04
)
 
$
0.65

 
$
(1.48
)
 
$
1.40

Diluted
 
$
(1.04
)
 
$
0.65

 
$
(1.48
)
 
$
1.39

Weighted-average common shares outstanding:
 
 
 
 
 
 

 
 

Basic
 
231,718

 
229,700

 
231,295

 
232,339

Diluted
 
231,718

 
230,190

 
231,295

 
233,172













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Laredo Petroleum, Inc.
Condensed consolidated statements of cash flows
 
 
Three months ended December 31,
 
Year ended December 31, 2019
 
 
2019
 
2018
 
2019
 
2018
 
 
(unaudited)
 
(unaudited)
Cash flows from operating activities:
 
 
 
 
 
 

 
 

Net income (loss)
 
$
(241,721
)
 
$
149,573

 
$
(342,459
)
 
$
324,595

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
 
 
 
 
 
Non-cash stock-based compensation, net
 
3,046

 
7,648

 
8,290

 
36,396

Depletion, depreciation and amortization
 
67,846

 
60,399

 
265,746

 
212,677

Impairment expense
 
222,999

 

 
620,889

 

Mark-to-market on derivatives:
 
 
 
 
 
 
 
 
(Gain) loss on derivatives, net
 
57,562

 
(112,195
)
 
(79,151
)
 
(42,984
)
Settlements received for matured commodity derivatives, net
 
14,394

 
12,033

 
63,221

 
6,090

Settlements paid for early terminations of commodity derivatives, net
 

 

 
(5,409
)
 

Premiums paid for commodity derivatives
 
(1,399
)
 
(5,405
)
 
(9,063
)
 
(20,335
)
Deferred income tax (benefit) expense
 
(1,776
)
 
3,288

 
(2,588
)
 
5,056

Other, net
 
6,996

 
3,544

 
21,791

 
15,882

Cash flows from operating activities before changes in operating assets and liabilities, net
 
127,947

 
118,885

 
541,267

 
537,377

Change in current assets and liabilities, net
 
(15,818
)
 
10,842

 
(64,123
)
 
1,157

Change in noncurrent assets and liabilities, net
 
(3,923
)
 
(451
)
 
(2,070
)
 
(730
)
Net cash provided by operating activities
 
108,206

 
129,276

 
475,074

 
537,804

Cash flows from investing activities:
 
 
 
 
 
 
 
 
Acquisitions of oil and natural gas properties, net of closing adjustments
 
(196,404
)
 
(1,198
)
 
(199,284
)
 
(17,538
)
Capital expenditures:
 
 
 
 
 
 
 
 
Oil and natural gas properties
 
(90,803
)
 
(151,114
)
 
(458,985
)
 
(673,584
)
Midstream service assets
 
(1,169
)
 
(1,020
)
 
(7,910
)
 
(6,784
)
Other fixed assets
 
(713
)
 
(1,363
)
 
(2,433
)
 
(7,308
)
Proceeds from dispositions of capital assets, net of selling costs
 
54

 
170

 
6,901

 
14,258

Net cash used in investing activities
 
(289,035
)
 
(154,525
)
 
(661,711
)
 
(690,956
)
Cash flows from financing activities:
 
 
 
 
 
 
 
 
Borrowings on Senior Secured Credit Facility
 
195,000

 
20,000

 
275,000

 
210,000

Payments on Senior Secured Credit Facility
 
(5,000
)
 

 
(90,000
)
 
(20,000
)
Share repurchases
 

 

 

 
(97,055
)
Other, net
 
(7
)
 
(7
)
 
(2,657
)
 
(6,801
)
Net cash provided by financing activities
 
189,993

 
19,993

 
182,343

 
86,144

Net increase (decrease) in cash and cash equivalents
 
9,164

 
(5,256
)
 
(4,294
)
 
(67,008
)
Cash and cash equivalents, beginning of period
 
31,693

 
50,407

 
45,151

 
112,159

Cash and cash equivalents, end of period
 
$
40,857

 
$
45,151

 
$
40,857

 
$
45,151



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Laredo Petroleum, Inc.
Total Costs Incurred
The following table presents the components of our costs incurred, excluding non-budgeted acquisition costs:
 
 
Three months ended December 31,
 
Year ended December 31, 2019
(in thousands)
 
2019
 
2018
 
2019
 
2018
 
 
(unaudited)
 
(unaudited)
Oil and natural gas properties
 
$
104,616

 
$
145,345

 
$
470,455

 
$
631,674

Midstream service assets
 
1,071

 
969

 
8,655

 
4,618

Other fixed assets
 
504

 
1,125

 
2,470

 
7,322

Total costs incurred, excluding non-budgeted acquisition costs
 
$
106,191

 
$
147,439

 
$
481,580

 
$
643,614































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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 Free Cash Flow, Adjusted Net Income and Adjusted EBITDA, as defined by us, may not be comparable to similarly titled measures used by other companies. Therefore, these non-GAAP financial measures should be considered in conjunction with net income or loss and other performance measures prepared in accordance with GAAP, such as operating income or loss or cash flows from operating activities. Free Cash Flow, Adjusted Net Income and Adjusted EBITDA should not be considered in isolation or as a substitute for GAAP measures, such as net income or loss, operating income or loss or any other GAAP measure of liquidity or financial performance.
Free Cash Flow (Unaudited)
Free Cash Flow, a non-GAAP financial measure, does not represent funds available for future discretionary use because it excludes funds required for future debt service, capital expenditures, acquisitions, working capital, income taxes, franchise taxes and other commitments and obligations. However, our management believes Free Cash Flow is useful to management and investors in evaluating operating trends in our business that are affected by production, commodity prices, operating costs and other related factors. There are significant limitations to the use of Free Cash Flow as a measure of performance, including the lack of comparability due to the different methods of calculating Free Cash Flow reported by different companies.
The following table presents a reconciliation of net cash provided by operating activities (GAAP) to cash flows from operating activities before changes in operating assets and liabilities, net, less costs incurred, excluding non-budgeted acquisition costs, for the calculation of Free Cash Flow (non-GAAP):
 
 
Three months ended December 31,
 
Year ended December 31, 2019
(in thousands)
 
2019
 
2018
 
2019
 
2018
 
 
(unaudited)
 
(unaudited)
Net cash provided by operating activities
 
$
108,206

 
$
129,276

 
$
475,074

 
$
537,804

Less:
 
 
 
 
 
 
 
 
(Increase) decrease in current assets and liabilities, net
 
(15,818
)
 
10,842

 
(64,123
)
 
1,157

Increase in noncurrent assets and liabilities, net
 
(3,923
)
 
(451
)
 
(2,070
)
 
(730
)
Cash flows from operating activities before changes in operating assets and liabilities, net
 
127,947

 
118,885

 
541,267

 
537,377

Less costs incurred, excluding non-budgeted acquisition costs:
 
 
 
 
 
 
 
 
Oil and natural gas properties(1)
 
104,616

 
145,345

 
470,455

 
631,674

Midstream service assets
 
1,071

 
969

 
8,655

 
4,618

Other fixed assets
 
504

 
1,125

 
2,470

 
7,322

Total costs incurred, excluding non-budgeted acquisition costs
 
106,191

 
147,439

 
481,580

 
643,614

Free Cash Flow (non-GAAP)
 
$
21,756

 
$
(28,554
)
 
$
59,687

 
$
(106,237
)
_____________________________________________________________________________
(1)
Includes non-cash stock-based compensation, net of $1.3 million and $1.9 million for the three months ended December 31, 2019 and 2018, respectively, and $4.5 million and $7.9 million for the years ended December 31, 2019 and 2018, respectively. Additionally, includes asset retirement costs of $0.1 million and $0.2 million for the three months ended December 31, 2019 and 2018, respectively, and $0.6 million and $0.7 million for the years ended December 31, 2019 and 2018, respectively.



11


Adjusted Net Income (Unaudited)
Adjusted Net Income is a non-GAAP financial measure we use to evaluate performance, prior to income taxes, mark-to-market on derivatives, premiums paid for derivatives, impairment expense, gains or losses on disposal of assets and other non-recurring income and expenses and after applying adjusted income tax expense. We believe Adjusted Net Income helps investors in the oil and natural gas industry to measure and compare our performance to other oil and natural gas companies by excluding from the calculation items that can vary significantly from company to company depending upon accounting methods, the book value of assets and other non-operational factors.
The following table presents a reconciliation of income (loss) before income taxes (GAAP) to Adjusted Net Income (non-GAAP):
 
 
Three months ended December 31,
 
Year ended December 31, 2019
(in thousands, except per share data)
 
2019
 
2018
 
2019
 
2018
 
 
(unaudited)

(unaudited)
Income (loss) before income taxes
 
$
(243,497
)
 
$
152,435

 
$
(345,047
)
 
$
328,844

Plus:
 
 
 
 
 
 
 
 
Mark-to-market on derivatives:
 
 
 
 
 
 
 
 
(Gain) loss on derivatives, net
 
57,562

 
(112,195
)
 
(79,151
)
 
(42,984
)
Settlements received for matured commodity derivatives, net
 
14,394

 
12,033

 
63,221

 
6,090

Settlements paid for early terminations of commodity derivatives, net
 

 

 
(5,409
)
 

Premiums paid for commodity derivatives
 
(1,399
)
 
(5,405
)
 
(9,063
)
 
(20,335
)
Organizational restructuring expenses
 

 

 
16,371

 

Impairment expense
 
222,999

 

 
620,889

 

Litigation settlement
 

 

 
(42,500
)
 

(Gain) loss on disposal of assets, net
 
(67
)
 
1,207

 
248

 
5,798

Write-off of debt issuance costs
 
935

 

 
935

 

Adjusted income before adjusted income tax expense
 
50,927


48,075


220,494


277,413

Adjusted income tax expense(1)
 
(11,204
)

(10,577
)

(48,509
)

(61,031
)
Adjusted Net Income
 
$
39,723


$
37,498


$
171,985


$
216,382

Net income (loss) per common share:
 
 
 
 
 
 
 
 
Basic
 
$
(1.04
)
 
$
0.65

 
$
(1.48
)
 
$
1.40

Diluted
 
$
(1.04
)
 
$
0.65

 
$
(1.48
)
 
$
1.39

Adjusted Net Income per common share:
 
 
 
 
 
 
 
 
Basic
 
$
0.17


$
0.16


$
0.74


$
0.93

Diluted
 
$
0.17


$
0.16


$
0.74


$
0.93

Adjusted diluted
 
$
0.17

 
$
0.16

 
$
0.74

 
$
0.93

Weighted-average common shares outstanding:
 
 
 
 
 
 

 
 

Basic
 
231,718

 
229,700

 
231,295

 
232,339

Diluted
 
231,718

 
230,190

 
231,295

 
233,172

Adjusted diluted
 
231,828

 
230,190

 
231,897

 
233,172

_______________________________________________________________________________
(1)
Adjusted income tax expense is calculated by applying a statutory tax rate of 22% for each of the periods ended December 31, 2019 and 2018.





12


Adjusted EBITDA (Unaudited)
Adjusted EBITDA is a non-GAAP financial measure that we define as net income or loss plus adjustments for non-cash stock-based compensation, net, depletion, depreciation and amortization, impairment expense, mark-to-market on derivatives, premiums paid for commodity derivatives, accretion expense, gains or losses on disposal of assets, write-off of debt issuance costs, interest expense, income taxes and other non-recurring income and expenses. Adjusted EBITDA provides no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, working capital movement or tax position. Adjusted EBITDA does not represent funds available for discretionary use because it excludes funds required for debt service, capital expenditures, working capital, income taxes, franchise taxes and other commitments and obligations. However, our management believes Adjusted EBITDA is useful to an investor in evaluating our operating performance because this measure:
is widely used by investors in the oil and natural gas industry to measure a company's operating performance without regard to items that can vary substantially from company to company depending upon accounting methods, the book value of assets, capital structure and the method by which assets were acquired, among other factors;
helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure; and
 is used by our management for various purposes, including as a measure of operating performance, in presentations to our board of directors and as a basis for strategic planning and forecasting.
There are significant limitations to the use of Adjusted EBITDA as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss and the lack of comparability of results of operations to different companies due to the different methods of calculating Adjusted EBITDA reported by different companies. Our measurements of Adjusted EBITDA for financial reporting as compared to compliance under our debt agreements differ.
The following table presents a reconciliation of net income (loss) (GAAP) to Adjusted EBITDA (non-GAAP):
 
 
Three months ended December 31,
 
Year ended December 31, 2019
(in thousands)
 
2019
 
2018
 
2019
 
2018
 
 
(unaudited)
 
(unaudited)
Net income (loss)
 
$
(241,721
)
 
$
149,573

 
$
(342,459
)
 
$
324,595

Plus:
 
 
 
 
 
 

 
 

Non-cash stock-based compensation, net
 
3,046

 
7,648

 
8,290

 
36,396

Depletion, depreciation and amortization
 
67,846

 
60,399

 
265,746

 
212,677

Impairment expense
 
222,999

 

 
620,889

 

Mark-to-market on derivatives:
 
 
 
 
 
 
 
 
(Gain) loss on derivatives, net
 
57,562

 
(112,195
)
 
(79,151
)
 
(42,984
)
Settlements received for matured commodity derivatives, net
 
14,394

 
12,033

 
63,221

 
6,090

Settlements paid for early terminations of commodity derivatives, net
 

 

 
(5,409
)
 

Premiums paid for commodity derivatives
 
(1,399
)
 
(5,405
)
 
(9,063
)
 
(20,335
)
Accretion expense
 
1,041

 
1,131

 
4,118

 
4,472

(Gain) loss on disposal of assets, net
 
(67
)
 
1,207

 
248

 
5,798

Write-off of debt issuance costs
 
935

 

 
935

 

Interest expense
 
15,044

 
15,117

 
61,547

 
57,904

Organizational restructuring expenses
 

 

 
16,371

 

Litigation settlement





(42,500
)


Income tax (benefit) expense

 
(1,776
)
 
2,862

 
(2,588
)
 
4,249

Adjusted EBITDA
 
$
137,904

 
$
132,370

 
$
560,195

 
$
588,862


Projected Free Cash Flow
Projected Free Cash Flow, a non-GAAP financial measure, is calculated as estimated cash flows from operating activities before changes in assets and liabilities, less estimated costs incurred, excluding non-budgeted acquisition costs, made during the period. Management believes this is useful to management and investors in evaluating the operating trends in its business due to production, commodity prices, operating costs and other related factors.


13



# # #

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

14

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