UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
ý☒QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2017March 31, 2021
or
o☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                             to                            
Commission File Number: 001-35380
Laredo Petroleum, Inc.
(Exact name of registrant as specified in its charter)
Delaware
 (State
45-3007926
(State or other jurisdiction of
incorporation or organization)
45-3007926
 (I.R.S.(I.R.S. Employer
Identification No.)
15 W. Sixth StreetSuite 900
Tulsa OklahomaOklahoma74119
(Address of principal executive offices)(Zip code)
(918) 513-4570
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Exchange Act:
Title of each classTrading symbolName of each exchange on which registered
Common stock, $0.01 par value per shareLPINew York Stock Exchange
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý☒  No o☐
Indicate by check mark whether the registrant has submitted electronically, and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý☒  No o☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one): 
Large accelerated filer☐Accelerated filer ☒
Non-accelerated filer ☐Smaller reporting company ☐
Large accelerated filer ý
Accelerated filer o
Non-accelerated filer o
Smaller reporting company o
(Do not check if a smaller reporting company)
Emerging growth companyo
☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o☐  No ý☒
Number of shares of registrant's common stock outstanding as of October 30, 2017: 242,512,535May 3, 2021: 12,898,823



LAREDO PETROLEUM, INC.
TABLE OF CONTENTS
Page
iii
1
Item 1.
Consolidated Financial Statements (Unaudited):
1
Consolidated balance sheets as of September 30, 2017March 31, 2021 and December 31, 20162020
1
Consolidated statements of operations for the three and nine months ended September 30, 2017 March 31, 2021 and 20162020
2
Consolidated statementstatements of stockholders' equity continuous quarterly presentation for the ninethree months ended September 30, 2017March 31, 2021 and 2020
3
Consolidated statements of cash flows for the ninethree months ended September 30, 2017March 31, 2021 and 20162020
4
Condensed notes to the consolidated financial statements:
5
Note 1—Organization and basis of presentation
5
Note 2—Basis of presentation and significantNew accounting policiesstandards
5
Note 3—DivestitureAcquisitions and divestiture
125
Note 4—Debt4—Leases
136
Note 5—Employee compensation5—Property and equipment
147
Note 6—Income taxesDebt
189
Note 7—DerivativesStockholders' equity
1811
Note 8—Equity Incentive Plan
12
Note 9—Derivatives
16
Note 10—Fair value measurements
2219
Note 9—11—Net income (loss)loss per common share
2621
Note 10—Credit risk
27
Note 11—12—Commitments and contingencies
2722
Note 12—Related parties13—Supplemental cash flow and non-cash information
2823
Note 13—Segments
28
Note 14—Subsidiary guarantors
31
Note 15—Recently issued or adopted accounting pronouncements
34
Note 16—Subsequent events
35
Note 17—Supplementary information
36
Note 14—Asset retirement obligations
23
Note 15—Revenue recognition
23
Note 16—Income taxes
23
Note 17—Related parties
24
Note 18—Subsequent events
25
Item 2.
Management's Discussion and Analysis of Financial Condition and Results of Operations
3726
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
5242
Item 4.
Controls and Procedures
5445
Part II
Item 1.
Legal Proceedings
55
Risk Factors46
55
Item 1.    Legal Proceedings
46
Item 1A.    Risk Factors
47
Item 2.
Repurchase    Purchases of Equity Securities
5548
Item 3.
Defaults Upon Senior Securities
5549
Item 4.
Mine Safety Disclosures
5550
Item 5.    Other Information
Other Information51
55
Item 6.    Exhibits
Exhibits52
57
5853


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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
Various statements contained in or incorporated by reference into this Quarterly Report on Form 10-Q (this "Quarterly Report") are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). These forward-looking statements include statements, projections and estimates concerning our operations, performance, business strategy, oil, natural gas liquids ("NGL") and natural gas reserves, drilling program capital expenditures, liquidity and capital resources, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, derivative activities and potential financing. Forward-looking statements are generally accompanied by words such as "estimate," "project," "predict," "believe," "expect," "anticipate," "potential," "could," "may," "will," "foresee," "plan," "goal," "should," "intend," "pursue," "target," "continue," "suggest" or the negative thereof or other variations thereof or other words that convey the uncertainty of future events or outcomes. Forward-looking statements are not guarantees of performance. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. Among the factors that significantly impact our business and could impact our business in the future are:
•the volatilityeffects, duration, government response or other implications of the coronavirus ("COVID-19") pandemic, or the threat and substantial decline in, oil, natural gas liquids ("NGL") and natural gas prices, which remain at low levels;occurrence of other epidemic or pandemic diseases;
revisions to our reserve estimates as a result of changes in commodity prices and other uncertainties;
impacts to our financial statements as a result of impairment write-downs;
our ability to discover, estimate, develop and replace oil, NGL and natural gas reserves;
•changes in domestic and global production, supply and demand for oil, NGL and natural gas;gas, including the effects from the COVID-19 pandemic and actions by the Organization of the Petroleum Exporting Countries members and other oil exporting nations ("OPEC+");
•the volatility of oil, NGL and natural gas prices, including in our area of operation in the Permian Basin;
•the potential impact of suspending drilling programs and completions activities or shutting in a portion of our wells, as well as costs to later restart, and co‐development considerations such as horizontal spacing, vertical spacing and parent‐child interactions on production of oil, NGL and natural gas from our wells;
•United States ("U.S.") and international economic conditions and legal, tax, political and administrative developments, including the effects of the recent U.S. presidential, congressional and state elections on energy, trade and environmental policies and existing and future laws and government regulations;
•our ability to comply with federal, state and local regulatory requirements;
•the ongoing instability and uncertainty in the United StatesU.S. and international energy, financial and consumer markets that could adversely affect the liquidity available to us and our customers and the demand for commodities, including oil, NGL and natural gas;
•our ability to execute our strategies, including our ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to our financial results and to successfully integrate acquired businesses, assets and properties;
•competition in the oil and natural gas industry;
•our ability to discover, estimate, develop and replace oil, NGL and natural gas reserves and inventory;
•drilling and operating risks, including risks related to hydraulic fracturing activities, and those related to inclement or extreme weather impacting our ability to produce existing wells and/or drill and complete new wells over an extended period of time;
•the long-term performance of wells that were completed using different technologies;
•revisions to our reserve estimates as a result of changes in commodity prices, decline curves and other uncertainties;
•impacts of impairment write-downs on our financial statements;
•capital requirements for our operations and projects;
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Table of Contents
•our ability to continue to maintain the borrowing capacity under our SeniorFifth Amended and Restated Credit Agreement (as amended, the "Senior Secured Credit Facility (as defined below)Facility") or access other means of obtaining capital and liquidity, especially during periods of sustained low commodity prices;
•our ability to comply with restrictions contained in our debt agreements, including our Senior Secured Credit Facility and the indentures governing our senior unsecured notes, as well as debt that could be incurred in the future;
•our ability to generate sufficient cash to service our indebtedness, fund our capital requirements and generate future profits;
•our ability to hedge, and regulations that affect our ability to hedge;
the potentially insufficient refining capacity in the United States Gulf Coast to refine all of the light sweet crude oil being produced in the United States, which could result in widening price discounts to world crude prices and potential shut-in of production due to lack of sufficient markets;
regulations that prohibit or restrict our ability to apply hydraulic fracturing to our oil and natural gas wells and to access and dispose of water used in these operations;
legislation or regulations that prohibit or restrict our ability to drill new allocation wells;
our ability to execute our strategies;
competition in the oil and natural gas industry;
the adverse outcome and impact of litigation, legal proceedings, investigations or insurance or other claims, including the adverse outcome and impact of pending or protracted litigation;
changes in the regulatory environment and changes in United States or international legal, political, administrative or economic conditions;
drilling and operating risks, including risks related to hydraulic fracturing activities;
risks related to the geographic concentration of our assets;
•the availability and increased costs of drilling and production equipment, supplies, labor and oil and natural gas processing and other servicesservices;
•the availability and costs of sufficient gathering, processing, storage and export capacity in the Permian Basin;Basin and refining capacity in the U.S. Gulf Coast;
•the availabilityimpact of sufficient pipelinerepurchases, if any, of securities from time to time;
•the effectiveness of our internal control over financial reporting and transportation facilities and gathering and processing capacity;

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our ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive toremediate a material weakness in our internal control over financial results and to successfully integrate acquired businesses, assets and properties;reporting;
•our ability to comply with federal, statemaintain the health and local regulatory requirements; and
our ability tosafety of, as well as recruit and retain, the qualified personnel necessary to operate our business.business;
•risks related to the geographic concentration of our assets; and
•our ability to secure or generate sufficient electricity to produce our wells without limitations.
These forward-looking statements involve a number of risks and uncertainties that could cause actual results to differ materially from those suggested by the forward-looking statements. Forward-looking statements should, therefore, be considered in light of various factors, including those set forth under "Part I, Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations" and elsewhere in this Quarterly Report, under "Part I, Item 1A. Risk Factors" and "Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in our Annual Report on Form 10-K for the fiscal year ended December 31, 20162020 (the "2016"2020 Annual Report"), and those set forth from time to time in our other filings with the Securities and Exchange Commission (the "SEC"). These documents are available through our website or through the SEC's Electronic Data Gathering and Analysis Retrieval system at http://www.sec.gov. In light of such risks and uncertainties, we caution you not to place undue reliance on these forward-looking statements. These forward-looking statements speak only as of the date of this Quarterly Report, or if earlier, as of the date they were made. We do not intend to, and disclaim any obligation to, update or revise any forward-looking statements unless required by securities law.

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Table of Contents

Part I


Item 1.    Consolidated Financial Statements (Unaudited)


Laredo Petroleum, Inc.
Consolidated balance sheets
(in thousands, except share data)
(Unaudited)
 March 31, 2021December 31, 2020
Assets  
Current assets:  
Cash and cash equivalents$44,262 $48,757 
Accounts receivable, net67,704 63,976 
Derivatives0 7,893 
Other current assets26,123 15,964 
Total current assets138,089 136,590 
Property and equipment: 
Oil and natural gas properties, full cost method: 
Evaluated properties7,953,141 7,874,932 
Unevaluated properties not being depleted60,260 70,020 
Less accumulated depletion and impairment(6,852,688)(6,817,949)
Oil and natural gas properties, net1,160,713 1,127,003 
Midstream service assets, net111,083 112,697 
Other fixed assets, net31,576 32,011 
Property and equipment, net1,303,372 1,271,711 
Operating lease right-of-use assets14,955 17,973 
Other noncurrent assets, net18,487 16,336 
Total assets$1,474,903 $1,442,610 
Liabilities and stockholders' equity 
Current liabilities: 
Accounts payable and accrued liabilities$49,065 $38,279 
Accrued capital expenditures27,924 28,275 
Undistributed revenue and royalties32,018 24,728 
Derivatives128,394 31,826 
Operating lease liabilities11,263 11,721 
Other current liabilities43,579 62,766 
Total current liabilities292,243 197,595 
Long-term debt, net1,145,374 1,179,266 
Derivatives29,821 12,051 
Asset retirement obligations66,280 64,775 
Operating lease liabilities6,459 8,918 
Other noncurrent liabilities3,294 1,448 
Total liabilities1,543,471 1,464,053 
Commitments and contingencies00
Stockholders' equity:
Preferred stock, $0.01 par value, 50,000,000 shares authorized and 0 issued as of March 31, 2021 and December 31, 20200 0 
Common stock, $0.01 par value, 22,500,000 shares authorized and 12,899,660 and 12,020,164 issued and outstanding as of March 31, 2021 and December 31, 2020, respectively129 120 
Additional paid-in capital2,426,769 2,398,464 
Accumulated deficit(2,495,466)(2,420,027)
Total stockholders' equity(68,568)(21,443)
Total liabilities and stockholders' equity$1,474,903 $1,442,610 
  September 30, 2017
December 31, 2016
Assets  
  
Current assets:  
  
Cash and cash equivalents $20,818
 $32,672
Accounts receivable, net 89,840
 86,867
Derivatives 15,611
 20,947
Other current assets 16,196
 14,291
Total current assets 142,465
 154,777
Property and equipment:    
Oil and natural gas properties, full cost method:    
Evaluated properties 5,863,536
 5,488,756
Unevaluated properties not being depleted 211,720
 221,281
Less accumulated depletion and impairment (4,616,246) (4,514,183)
Oil and natural gas properties, net 1,459,010
 1,195,854
Midstream service assets, net 130,407
 126,240
Other fixed assets, net 41,902
 44,773
Property and equipment, net 1,631,319
 1,366,867
Derivatives 4,345
 8,718
Investment in equity method investee (Note 16.a) 276,435
 243,953
Other assets, net 11,762
 8,031
Total assets $2,066,326
 $1,782,346
Liabilities and stockholders' equity    
Current liabilities:    
Accounts payable $22,795
 $15,054
Undistributed revenue and royalties 33,222
 26,838
Accrued capital expenditures 70,001
 30,845
Derivatives 4,170
 20,993
Other current liabilities 93,072
 94,215
Total current liabilities 223,260
 187,945
Long-term debt, net 1,440,968
 1,353,909
Derivatives 362
 5,694
Asset retirement obligations 52,181
 50,604
Other noncurrent liabilities 3,330
 3,621
Total liabilities 1,720,101
 1,601,773
Commitments and contingencies 

 

Stockholders' equity:    
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued as of September 30, 2017 and December 31, 2016 —
 —
Common stock, $0.01 par value, 450,000,000 shares authorized and 242,526,932 and 241,929,070 issued and outstanding as of September 30, 2017 and December 31, 2016, respectively 2,425
 2,419
Additional paid-in capital 2,421,469
 2,396,236
Accumulated deficit (2,077,669) (2,218,082)
Total stockholders' equity 346,225
 180,573
Total liabilities and stockholders' equity $2,066,326
 $1,782,346


The accompanying notes are an integral part of these unaudited consolidated financial statements.

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Table of Contents
Laredo Petroleum, Inc.
Consolidated statements of operations
(in thousands, except per share data)
(Unaudited)
 Three months ended March 31,
 20212020
Revenues:
Oil sales$127,701 $119,978 
NGL sales41,678 11,558 
Natural gas sales33,078 4,349 
Midstream service revenues1,296 2,683 
Sales of purchased oil46,477 66,424 
Total revenues250,230 204,992 
Costs and expenses:
Lease operating expenses18,918 22,040 
Production and ad valorem taxes13,283 9,244 
Transportation and marketing expenses12,127 13,544 
Midstream service expenses858 1,170 
Costs of purchased oil49,916 79,297 
General and administrative13,073 12,562 
Depletion, depreciation and amortization38,109 61,302 
Impairment expense0 186,699 
Other operating expenses1,143 1,106 
Total costs and expenses147,427 386,964 
Operating income (loss)102,803 (181,972)
Non-operating income (expense):
Gain (loss) on derivatives, net(154,365)297,836 
Interest expense(25,946)(24,970)
Loss on extinguishment of debt0 (13,320)
Loss on disposal of assets, net(72)(602)
Other income, net1,379 91 
Total non-operating income (expense), net(179,004)259,035 
Income (loss) before income taxes(76,201)77,063 
Income tax benefit (expense):
Deferred762 (2,417)
Total income tax benefit (expense)762 (2,417)
Net income (loss)$(75,439)$74,646 
Net income (loss) per common share (1):
Basic$(6.33)$6.43 
Diluted$(6.33)$6.39 
Weighted-average common shares outstanding(1):
Basic11,918 11,618 
Diluted11,918 11,673 

  Three months ended September 30, Nine months ended September 30,
  2017 2016 2017 2016
Revenues:





  
  
Oil, NGL and natural gas sales
$157,558

$114,805

$438,131

$290,473
Midstream service revenues
2,446

2,488

8,148

5,921
Sales of purchased oil 45,814
 42,441
 135,546
 116,670
Total revenues
205,818

159,734

581,825

413,064
Costs and expenses:
       
Lease operating expenses
19,594

18,177

56,690

57,920
Production and ad valorem taxes 9,558
 7,066
 26,811
 21,483
Midstream service expenses 1,174
 1,039
 2,986
 2,826
Costs of purchased oil 47,385
 44,232
 141,661
 121,190
General and administrative
25,000

26,105
 72,605
 66,058
Depletion, depreciation and amortization
41,212

35,158

113,327

110,813
Impairment expense
—

—

—

162,027
Other operating expenses 1,443
 2,465
 3,906
 4,169
Total costs and expenses
145,366

134,242

417,986

546,486
Operating income (loss)
60,452

25,492

163,839

(133,422)
Non-operating income (expense):



     
Gain (loss) on derivatives, net
(27,441)
6,850

38,127

(43,783)
Income from equity method investee (Note 16.a)
2,371

265

7,910

6,259
Interest expense
(23,697)
(23,077)
(69,590)
(70,294)
Interest and other income
333

33

527

143
Write-off of debt issuance costs
—

—
 —
 (842)
Loss on disposal of assets, net
(991)
(78)
(400)
(379)
Non-operating expense, net
(49,425)
(16,007)
(23,426)
(108,896)
Income (loss) before income taxes
11,027

9,485

140,413

(242,318)
Income tax:



 





Deferred
—

—

—

—
Total income tax
—

—

—

—
Net income (loss)
$11,027
 $9,485

$140,413

$(242,318)
Net income (loss) per common share:



 
 



Basic
$0.05

$0.04

$0.59
 $(1.09)
Diluted
$0.05
 $0.04

$0.57
 $(1.09)
Weighted-average common shares outstanding:






 
  
Basic
239,306

234,639

239,017
 221,303
Diluted
244,887

238,108

244,693
 221,303
(1)For the three months ended March 31, 2020, net income per common share and weighted-average common shares outstanding were retroactively adjusted for the Company's 1-for-20 reverse stock split effective June 1, 2020 as discussed in Note 7.b.
The accompanying notes are an integral part of these unaudited consolidated financial statements.

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Table of Contents
Laredo Petroleum, Inc.
Consolidated statementstatements of stockholders' equity
(in thousands)
(Unaudited)
 Common stockAdditional
paid-in capital		Treasury stock
(at cost)		Accumulated deficit 
 SharesAmountSharesAmountTotal
Balance, December 31, 202012,020 $120 $2,398,464 0 $0 $(2,420,027)$(21,443)
Restricted stock awards188 2 (2)— — — 0 
Restricted stock forfeitures(1)— — — — — 0 
Stock exchanged for tax withholding— — — 37 (1,290)— (1,290)
Retirement of treasury stock(37)— (1,290)(37)1,290 — 0 
Share-settled equity-based compensation— — 2,738 — — — 2,738 
Issuance of common stock, net of costs724 7 26,859 — — — 26,866 
Performance share conversion6 — — — — — — 
Net loss— — — — — (75,439)(75,439)
Balance, March 31, 202112,900 $129 $2,426,769 0 $0 $(2,495,466)$(68,568)
Common stockAdditional
paid-in capital		Treasury stock
(at cost)		Accumulated deficit
Shares (1)
Amount
Shares (1)
AmountTotal
Balance, December 31, 201911,865 $2,373 $2,385,355 0 $0 $(1,545,854)$841,874 
Restricted stock awards138 28 (28)— — — 0 
Restricted stock forfeitures(7)(2)2 — — — 0 
Stock exchanged for tax withholding— — — 26 (640)— (640)
Retirement of treasury stock(26)(5)(635)(26)640 — 0 
Share-settled equity-based compensation— — 3,341 — — — 3,341 
Net income— — — — — 74,646 74,646 
Balance, March 31, 202011,970 $2,394 $2,388,035 0 $0 $(1,471,208)$919,221 

  Common Stock 
Additional
paid-in capital
 
Treasury Stock
(at cost)
 Accumulated deficit  
  Shares Amount  Shares Amount  Total
Balance, December 31, 2016 241,929
 $2,419
 $2,396,236
 —
 $—
 $(2,218,082) $180,573
Restricted stock awards 1,213
 12
 (12) —
 —
 —
 —
Restricted stock forfeitures (264) (3) 3
 —
 —
 —
 —
Performance share conversion 150
 2
 (2) —
 —
 —
 —
Vested stock exchanged for tax withholding —
 —
 —
 545
 (7,638) —
 (7,638)
Retirement of treasury stock (545) (5) (7,633) (545) 7,638
 —
 —
Exercise of stock options 44
 —
 358
 —
 —
 —
 358
Stock-based compensation —
 —
 32,519
 —
 —
 —
 32,519
Net income —
 —
 —
 —
 —
 140,413
 140,413
Balance, September 30, 2017 242,527
 $2,425
 $2,421,469
 —
 $—
 $(2,077,669) $346,225
(1) Shares presented were retroactively adjusted for the Company's 1-for-20 reverse stock split effective June 1, 2020 as discussed in Note 7.b.
The accompanying notes are an integral part of thisthese unaudited consolidated financial statement.statements.

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Table of Contents
Laredo Petroleum, Inc.
Consolidated statements of cash flows
(in thousands)
(Unaudited)
 Nine months ended September 30, Three months ended March 31,
 2017 2016 20212020
Cash flows from operating activities:
 

 
Cash flows from operating activities:  
Net income (loss)
$140,413

$(242,318)Net income (loss)$(75,439)$74,646 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:





Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Share-settled equity-based compensation, netShare-settled equity-based compensation, net2,068 2,376 
Depletion, depreciation and amortization
113,327

110,813
Depletion, depreciation and amortization38,109 61,302 
Impairment expense
—

162,027
Impairment expense0 186,699 
Non-cash stock-based compensation, net of amounts capitalized
26,877

19,562
Mark-to-market on derivatives:





Mark-to-market on derivatives:
(Gain) loss on derivatives, net
(38,127)
43,783
(Gain) loss on derivatives, net154,365 (297,836)
Cash settlements received for matured derivatives, net
34,791

157,626
Cash settlements received for early terminations of derivatives, net
4,234

80,000
Change in net present value of derivative deferred premiums
199

184
Cash premiums paid for derivatives
(13,542)
(86,972)
Settlements (paid) received for matured derivatives, netSettlements (paid) received for matured derivatives, net(41,174)47,723 
Premiums received (paid) for commodity derivativesPremiums received (paid) for commodity derivatives9,041 (477)
Amortization of debt issuance costs
3,132

3,231
Amortization of debt issuance costs989 1,217 
Write-off of debt issuance costs
—
 842
Income from equity method investee (Note 16.a)
(7,910)
(6,259)
Cash settlement of performance unit awards —
 (6,394)
Amortization of operating lease right-of-use assetsAmortization of operating lease right-of-use assets2,997 4,377 
Loss on extinguishment of debtLoss on extinguishment of debt0 13,320 
Deferred income tax (benefit) expenseDeferred income tax (benefit) expense(762)2,417 
Other, net
3,445

2,973
Other, net1,491 1,327 
(Increase) decrease in accounts receivable (2,973) 6,476
Increase in other assets (3,220) (594)
Increase in accounts payable 7,741
 5,852
Increase (decrease) in undistributed revenues and royalties 6,384
 (9,866)
(Decrease) increase in other accrued liabilities (2,430) 4,785
Decrease in other noncurrent liabilities (290) (297)
Changes in operating assets and liabilities:Changes in operating assets and liabilities:
Accounts receivable, netAccounts receivable, net(3,728)9,635 
Other current assetsOther current assets(10,264)4,033 
Other noncurrent assets, netOther noncurrent assets, net(1,636)(2,964)
Accounts payable and accrued liabilitiesAccounts payable and accrued liabilities9,065 25,059 
Undistributed revenue and royaltiesUndistributed revenue and royalties7,290 (4,937)
Other current liabilitiesOther current liabilities(19,622)(15,082)
Other noncurrent liabilitiesOther noncurrent liabilities(1,639)(3,246)
Net cash provided by operating activities 272,051
 245,454
Net cash provided by operating activities71,151 109,589 
Cash flows from investing activities:





Cash flows from investing activities:
Acquisitions of oil and natural gas properties, netAcquisitions of oil and natural gas properties, net0 (22,876)
Capital expenditures:





Capital expenditures:
Acquisitions of oil and natural gas properties
—
 (115,600)
Oil and natural gas properties
(381,165)
(276,735)Oil and natural gas properties(68,329)(135,376)
Midstream service assets
(11,680)
(4,231)Midstream service assets(329)(761)
Other fixed assets
(3,604)
(982)Other fixed assets(551)(829)
Investment in equity method investee (Note 16.a) (24,572) (58,712)
Proceeds from dispositions of capital assets, net of selling costs
64,128

365
Proceeds from dispositions of capital assets, net of selling costs189 51 
Net cash used in investing activities
(356,893)
(455,895)Net cash used in investing activities(69,020)(159,791)
Cash flows from financing activities:





Cash flows from financing activities:
Borrowings on Senior Secured Credit Facility
155,000

214,682
Borrowings on Senior Secured Credit Facility15,000 0 
Payments on Senior Secured Credit Facility
(70,000)
(279,682)Payments on Senior Secured Credit Facility(50,000)(100,000)
Proceeds from issuance of common stock, net of offering costs —
 276,052
Purchase of treasury stock
(7,638)
(1,613)
Proceeds from exercise of stock options
358

208
Issuance of January 2025 Notes and January 2028 NotesIssuance of January 2025 Notes and January 2028 Notes0 1,000,000 
Extinguishment of debtExtinguishment of debt0 (808,855)
Proceeds from issuance of common stock, net of costsProceeds from issuance of common stock, net of costs26,866 0 
Stock exchanged for tax withholdingStock exchanged for tax withholding(1,290)(640)
Payments for debt issuance costs
(4,732)
—
Payments for debt issuance costs0 (18,383)
Net cash provided by financing activities
72,988

209,647
Net decrease in cash and cash equivalents
(11,854)
(794)
Other liabilitiesOther liabilities2,798 0 
Net cash (used in) provided by financing activitiesNet cash (used in) provided by financing activities(6,626)72,122 
Net (decrease) increase in cash and cash equivalentsNet (decrease) increase in cash and cash equivalents(4,495)21,920 
Cash and cash equivalents, beginning of period
32,672

31,154
Cash and cash equivalents, beginning of period48,757 40,857 
Cash and cash equivalents, end of period
$20,818

$30,360
Cash and cash equivalents, end of period$44,262 $62,777 
 
The accompanying notes are an integral part of these unaudited consolidated financial statements.

4
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)


Note 1—Organization and basis of presentation
a.    Organization
Laredo Petroleum, Inc. ("Laredo"), together with its wholly-owned subsidiaries, Laredo Midstream Services, LLC ("LMS") and Garden City Minerals, LLC ("GCM"), is an independent energy company 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 inof West Texas. LMSThe Company has identified 1 operating segment: exploration and GCM (together, the "Guarantors") guarantee all of Laredo's debt instruments.production. In these notes, the "Company" refers to Laredo, LMS and GCM collectively, unless the context indicates otherwise. All amounts, dollars and percentages presented in these unaudited consolidated financial statements and the related notes are rounded and, therefore, approximate.
As of September 30, 2017, LMS held 49% of the ownership units of Medallion Gathering & Processing, LLC, a Texas limited liability company formed on October 12, 2012, which, together with its wholly-owned subsidiaries (collectively, "Medallion"), is focused on developing midstream solutions and providing midstream infrastructure in the Midland Basin. Prior to the sale of Medallion, the Company accounted for Medallion as an equity method investment. See Note 16.a for discussion of the disposition of Medallion subsequent to September 30, 2017.
The Company operates in two business segments: (i) exploration and production and (ii) midstream and marketing. The exploration and production segment is engaged in the acquisition, exploration and development of oil and natural gas properties. The midstream and marketing segment provides Laredo's exploration and production segment and third parties with products and services that need to be delivered by midstream infrastructure, including oil and liquids-rich natural gas gathering services as well as rig fuel, natural gas lift and water delivery and takeaway.
Note 2—b.    Basis of presentation and significant accounting policies
a.    Basis of presentation
The accompanying unaudited consolidated financial statements were derived from the historical accounting records of the Company and reflect the historical financial position, results of operations and cash flows for the periods described herein. The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). All material intercompany transactions and account balances have been eliminated in the consolidation of accounts. The Company uses the equity method of accounting to record its net interests when the Company holds 20% to 50% of the voting rights and/or has the ability to exercise significant influence but does not control the entity. Under the equity method, the Company's proportionate share of the investee's net income is included in the unaudited consolidated statements of operations. See Note 2.h for additional discussion of the Company's equity method investment.
The accompanyingunaudited consolidated financial statements have not been audited by the Company's independent registered public accounting firm, except that the consolidated balance sheet as of December 31, 20162020 is derived from the Company's audited consolidated financial statements. In the opinion of management, the accompanying unaudited consolidated financial statements reflect all necessary adjustments to present fairly the Company's financial position as of September 30, 2017,March 31, 2021, results of operations for the three and nine months ended September 30, 2017March 31, 2021 and 20162020 and cash flows for the ninethree months ended September 30, 2017March 31, 2021 and 2016.2020.
Certain disclosures have been condensed or omitted from thesethe unaudited consolidated financial statements. Accordingly, thesethe unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in the 20162020 Annual Report.
b.    Significant accounting policies
See Note 2 in the 2020 Annual Report for discussion of significant accounting policies.
Use of estimates in the preparation of interim unaudited consolidated financial statements
The preparation of the accompanying unaudited consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ. The interim results reflected
See Note 2.b in the unaudited consolidated financial statements2020 Annual Report for further information regarding the use of estimates and assumptions.
Note 2—New accounting standards
The Company considered the applicability and impact of all accounting standard updates ("ASU") issued by the Financial Accounting Standards Board to the Accounting Standards Codification ("ASC") and has determined there are no ASUs that are not necessarily indicativeyet adopted and meaningful to disclose as of March 31, 2021.
Note 3—Acquisitions and divestiture
a.    2020 Asset acquisitions
On October 16, 2020 and November 16, 2020, the results that may be expectedCompany closed a bolt-on acquisition of 2,758 and 80 net acres, respectively, including production of 210 BOE per day, in Howard County, Texas for other interim periods or foran aggregate purchase price of $11.6 million, subject to customary post-closing purchase price adjustments.
On April 30, 2020, the full year.
Significant estimates include, but are not limited to, (i) estimates of the Company's reserves of oil, NGL and natural gas, (ii) future cash flows from oil and natural gas properties, (iii) depletion, depreciation and amortization, (iv) impairments, (v) asset retirement obligations, (vi) stock-based compensation, (vii) deferred income taxes, (viii) fair value of assets acquired and liabilities assumed inCompany closed an acquisition (ix) fair value of derivatives and deferred premiums and (x)180 net acres in Howard County, Texas for $0.6 million. The acquisition also provides for one or more potential contingent liabilities. Aspayments to be paid by the Company if the arithmetic average
5
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)


of the monthly settlement West Texas Intermediate ("WTI") NYMEX prices exceed certain thresholds for the contingency period beginning on January 1, 2021 and ending on the earlier of December 31, 2022 or the date the counterparty has received the maximum consideration of $1.2 million. The fair value is a market-based measurement, it is determined based onof this contingent consideration was $0.2 million as of the assumptions that would be used by market participants. These estimates and assumptions are based on management's best judgment. Management evaluates its estimates and assumptions on an ongoingacquisition date, which was recorded as part of the basis using historical experience and other factors, including the current economic environment. Such estimates and assumptions are adjusted when facts and circumstances dictate. Illiquid credit markets and volatile equity and energy markets have combined to increase the uncertainty inherent in such estimates and assumptions. Management believes its estimates and assumptions to be reasonable under the circumstances. As future events and their effects cannot be determined with precision, actual values and results could differ from these estimates. Any changes in estimates resulting from future changes in the economic environment will be reflected in the financial statements in future periods.
c.    Reclassifications
Certain amounts in the accompanying unaudited consolidated financial statements have been reclassified to conform to the 2017 presentation. These reclassifications had no impact on previously reported balance sheets or stockholders' equity.
d.    Accounts receivable
The Company sells produced oil, NGL and natural gas and purchased oil to various customers and participates with other parties in the development and operation of oil and natural gas properties.properties acquired and as a contingent consideration derivative liability. See Notes 9.c and 10.a for additional discussion of this contingent consideration.
On February 4, 2020, the Company closed a transaction for $22.5 million acquiring 1,180 net acres and divesting 80 net acres in Howard County, Texas.
All transaction costs were capitalized and are included in "Oil and natural gas properties" on the consolidated balance sheet.
b.    2020 Divestiture
On April 9, 2020, the Company closed a divestiture of 80 net acres and working interests in 2 producing wells in Glasscock County, Texas for $0.7 million, net of customary post-closing sales price adjustments. The majoritydivestiture was recorded as an adjustment to oil and natural gas properties pursuant to the rules governing full cost accounting. Effective at closing, the operations and cash flows of these oil and natural gas properties were eliminated from the ongoing operations of the Company, and the Company has no continuing involvement in the properties. This divestiture did not represent a strategic shift and has not had a major effect on the Company's accounts receivable are unsecured. Accounts receivable for joint interest billingsfuture operations or financial results.
c.    Exchange of unevaluated oil and natural gas properties
From time to time, the Company exchanges undeveloped acreage with third parties. The exchanges are recorded as amounts billed to customers less an allowance for doubtful accounts.
The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses, current receivables aging and existing industry and economic data. The Company reviews its allowance for doubtful accounts quarterly. Past due amounts greater than 90 days and greater than a specified amount are reviewed individually for collectability. Account balances are charged off against the allowance after all means of collection have been exhaustedat fair value and the potentialdifference is accounted for recovery is remote.
Accounts receivable consistedas an adjustment of capitalized costs with no gain or loss recognized pursuant to the following components as ofrules governing full cost accounting, unless such adjustment would significantly alter the dates presented:
(in thousands) September 30, 2017 December 31, 2016
Oil, NGL and natural gas sales $62,055
 $46,999
Sales of purchased oil and other products 15,624
 16,213
Joint operations, net(1)
 8,736
 12,175
Matured derivatives 3,345
 11,059
Other 80
 421
Total $89,840
 $86,867

(1)Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.1 million and $0.2 million as of September 30, 2017 and December 31, 2016, respectively. As the operator of the majority of its wells, the Company has the ability to realize some or all of these receivables through the netting of production revenues.
e.    Derivatives
The Company uses derivatives to reduce exposure to fluctuations in the pricesrelationship between capitalized costs and proved reserves of oil, NGL and natural gas. By removing a significant portion of the price volatility associated with future production, the
Note 4—Leases
The Company expects to mitigate, but not eliminate, the potential effects of variability in cash flows from operations due to fluctuations in commodity prices. These transactions are in the form of puts, swaps, collars, basis swapshas recognized operating lease right-of-use assets and call spreads.
Derivatives are recorded at fair value and are presented on a net basisoperating lease liabilities on the unaudited consolidated balance sheets for leases of commercial real estate with lease terms extending into 2027 and drilling, completion, production and other equipment leases with lease terms extending into 2022. The Company's lease costs include those that are recognized in net income (loss) during the period and capitalized as assets and/or liabilities. part of the cost of another asset in accordance with GAAP.
The lease costs related to drilling, completion and production activities are reflected at the Company's net ownership, which is consistent with the principles of proportional consolidation, and lease commitments are reflected on a gross basis. As of March 31, 2021, the Company nets the fair valuehad an average working interest of derivatives by counterparty where the right of offset exists. The Company determines the fair value of its derivatives by utilizing pricing models for substantially similar instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties.97% in Laredo-operated active productive wells. See Note 8.a5 in the 2020 Annual Report for additional discussion regarding the fair value of the Company's derivatives. leases.
The Company's derivatives were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the unaudited consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities. See Notes 7 and 8.a for discussion regarding the Company's derivatives.
6
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)


f.    Other current assets and liabilities
Other current assets consisted of the following components as of the dates presented:
(in thousands) September 30, 2017 December 31, 2016
Inventory(1)
 $8,623
 $8,063
Prepaid expenses and other 7,573
 6,228
Total other current assets $16,196
 $14,291

(1)See Note 2.i for discussion of inventory held by the Company.
Other current liabilities consisted of the following components as of the dates presented:
(in thousands) September 30, 2017 December 31, 2016
Accrued interest payable $21,832
 $24,152
Accrued compensation and benefits 16,498
 25,947
Purchased oil payable 16,070
 17,213
Lease operating expense payable 11,442
 10,572
Other accrued liabilities 27,230
 16,331
Total other current liabilities $93,072
 $94,215
g.    Note 5—Property and equipment
The following table sets forthpresents the Company's property and equipment as of the dates presented:
(in thousands) September 30, 2017 December 31, 2016(in thousands)March 31, 2021December 31, 2020
Evaluated oil and natural gas properties $5,863,536
 $5,488,756
Evaluated oil and natural gas properties$7,953,141 $7,874,932 
Less accumulated depletion and impairment (4,616,246) (4,514,183)Less accumulated depletion and impairment(6,852,688)(6,817,949)
Evaluated oil and natural gas properties, net 1,247,290
 974,573
Evaluated oil and natural gas properties, net1,100,453 1,056,983 
    
Unevaluated properties not being depleted 211,720
 221,281
Unevaluated oil and natural gas properties not being depletedUnevaluated oil and natural gas properties not being depleted60,260 70,020 
    
Midstream service assets 161,144
 150,629
Midstream service assets182,405 181,718 
Less accumulated depreciation and impairment (30,737) (24,389)Less accumulated depreciation and impairment(71,322)(69,021)
Midstream service assets, net 130,407
 126,240
Midstream service assets, net111,083 112,697 
    
Depreciable other fixed assets 50,767
 52,491
Depreciable other fixed assets37,612 37,454 
Less accumulated depreciation and amortization (23,779) (22,632)Less accumulated depreciation and amortization(24,937)(24,344)
Depreciable other fixed assets, net 26,988
 29,859
Depreciable other fixed assets, net12,675 13,110 
    
Land 14,914
 14,914
Land18,901 18,901 
    
Total property and equipment, net $1,631,319
 $1,366,867
Total property and equipment, net$1,303,372 $1,271,711 
ForSee Note 10.b for discussion of impairments of long-lived assets during the three months ended September 30, 2017March 31, 2020. See Note 6 in the 2020 Annual Report for additional discussion of the Company's property and 2016, depletion expense was $6.80 per barrel of oil equivalent ("BOE") sold and $6.71 per BOE sold, respectively. For the nine months ended September 30, 2017 and 2016, depletion expense was $6.57 per BOE sold and $7.55 per BOE sold, respectively.equipment.
The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain related employeeemployee-related costs, incurred for the purpose of acquiring, exploring for or developing oil and natural gas properties, are capitalized and, once evaluated, depleted on a composite unit of productionunit-of-production method based on estimates of proved oil, NGL and natural gas reserves. Such amountsThe depletion base includes estimated future development costs and dismantlement, restoration and abandonment costs, net of estimated salvage values. Capitalized costs include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Costs, including related employeeemployee-related costs, associated with production and general corporate activities are expensed in the period incurred. Sales of oil and natural gas
Table of Contents
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)


properties, whether or not being depleted currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, NGL and natural gas.
The following table presents capitalized employee-related costs for the periods presented:
  Three months ended September 30, Nine months ended September 30,
(in thousands) 2017 2016 2017 2016
Capitalized employee-related costs $6,938
 $6,149
 $17,911
 $12,598
The Company excludes theunevaluated property acquisition costs directly associated with acquisition and evaluation of unevaluated propertiesexploration costs from the depletion calculation until it is determined whether or not proved reserves can be assigned to the properties. The Company capitalizes a portion of its interest costs to its unevaluated properties. Capitalized interest becomes a part of the cost of the unevaluated properties and issuch costs become subject to depletion when proved reserves can be assigned to the associated properties. All items classified as unevaluated properties are assessed on a quarterly basis for possible impairment. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of evaluatedproved reserves and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion.
Sales of oil and natural gas properties, whether or not being depleted currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, NGL and natural gas.

7
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
The following table presents costs incurred in the acquisition, exploration and development of oil and natural gas properties, with asset retirement obligations included in evaluated property acquisition costs and development costs, for the periods presented:
 Three months ended March 31,
(in thousands)20212020
Property acquisition costs:   
Evaluated$0  $7,586 
Unevaluated0 15,556 
Exploration costs3,957 6,710 
Development costs64,492 146,158 
Total oil and natural gas properties costs incurred$68,449 $176,010 
The aforementioned total oil and natural gas properties costs incurred included certain employee-related costs as shown in the table below.
The following table presents capitalized employee-related costs incurred in the acquisition, exploration and development of oil and natural gas properties for the periods presented:
Three months ended March 31,
(in thousands)20212020
Capitalized employee-related costs$4,241 $4,505 
The following table presents depletion expense, which is included in "Depletion, depreciation and amortization" on the unaudited consolidated statements of operations, and depletion expense per BOE sold of evaluated oil and natural gas properties for the periods presented:
Three months ended March 31,
(in thousands except per BOE data)20212020
Depletion expense of evaluated oil and natural gas properties$34,725 $57,752 
Depletion expense per BOE sold$4.88 $7.33 
The full cost ceiling is based principally on the estimated future net revenuescash flows from proved oil, NGL and natural gas propertiesreserves, which exclude the effect of the Company's commodity derivative transactions, discounted at 10%. The SEC guidelines require companies to use the unweighted arithmetic average first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period before differentials ("Benchmark Prices"). The Benchmark Prices are then adjusted for quality, certain transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellheaddelivery point ("Realized Prices"). without giving effect to the Company's commodity derivative transactions. The Realized Prices are utilized to calculate the discountedestimated future net revenuescash flows in the full cost ceiling calculation.
Significant inputs included in the calculation of discounted cash flows used in the impairment analysis include the Company's estimate of operating and development costs, anticipated production of proved reserves and other relevant data. In the event the unamortized cost of evaluated oil and natural gas properties being depleted exceeds the full cost ceiling, as defined by the SEC, the excess is charged to expenseexpensed in the period such excess occurs. Once incurred, a write-down of oil and natural gas properties is not reversible.
Full The unamortized cost ceiling impairment expense forof evaluated oil and natural gas properties being depleted did not exceed the nine months ended September 30, 2016 was $161.1 million and is included in the "Impairment expense" line item in the unaudited consolidated statements of operations and in the financial information provided for the Company's exploration and production segment presented in Note 13. There was no full cost ceiling impairment expense recorded duringas of March 31, 2021, and as such, the nine months ended September 30, 2017.
h.    Variable interest entity
Medallion was established for the purpose of developing midstream solutions and providing midstream infrastructure to bring oil to market in the Midland Basin. As of September 30, 2017, LMS held 49% of Medallion's ownership units. LMS and the third-party 51% interest-holder agreed that the voting rights of Medallion, the profit and loss sharing and the additional capital contribution requirements would be equal to the ownership unit percentage held. Additionally, Medallion required a super-majority vote of 75% for many key operating and business decisions. The Company has determined that Medallion is a variable interest entity ("VIE"). However, LMS was not considered to be the primary beneficiary of the VIE because LMS did not have the power to direct the activities that most significantly affected Medallion's economic performance. As such, prior to its sale, Medallion was accounted for under the equity method of accounting. The Company's proportionate share of Medallion's net income is reflected in the unaudited consolidated statements of operations as "Income from equity method investee" and the carrying amount is reflected in the unaudited consolidated balance sheets as "Investment in equity method investee." The Company has elected to classify distributions received from Medallion using the cumulative earnings approach. No such distributions have been received through September 30, 2017.record a first-quarter full cost ceiling impairment.
LMS contributed $24.6 million to Medallion during the three and nine months ended September 30, 2017. LMS contributed $16.0 million and $58.7 million to Medallion during the three and nine months ended September 30, 2016, respectively. Medallion continued expansion activities on existing portions of its pipeline infrastructure in order to gather and transport additional third-party oil production during each of the nine months ended September 30, 2017 and 2016. See Note 12.a for discussion of items included in the Company's unaudited consolidated financial statements related to Medallion. See Note 16.a for discussion regarding an additional contribution made to Medallion subsequent to September 30, 2017.
8
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)


On October 30, 2017, LMS, together withThe following table presents the third-party 51% interest holder, completedBenchmark Prices and the previously announced sale of 100%Realized Prices as of the ownership interests in Medallion (the "Medallion Sale"). LMS has a Transportation Services Agreement (the "TA") with a wholly-owned subsidiary of Medallion, under which LMS receives firm transportation ofdates presented:
March 31, 2021December 31, 2020September 30, 2020June 30, 2020
Benchmark Prices:
   Oil ($/Bbl)$36.49 $36.04 $39.88 $43.60 
   NGL ($/Bbl)(1)
$19.24 $16.63 $16.95 $16.87 
   Natural gas ($/MMBtu)$1.69 $1.21 $1.06 $0.87 
Realized Prices:
   Oil ($/Bbl)$38.28 $37.69 $41.08 $44.97 
   NGL ($/Bbl)$9.92 $7.43 $7.71 $7.66 
   Natural gas ($/Mcf)$1.20 $0.79 $0.68 $0.53 

(1)    Based on the Company's crude oil production from Reagan and Glasscock County, Texas to Colorado City, Texas that continues to be in effect after the Medallion Sale. Historically, the Company's crude oil purchasers have fulfilled the commitment by transporting crude oil, purchased from the Company, under the TA, as agent. As of September 30, 2017, the Company's maximum exposure to loss associated with future commitments under the TA is $146.2 million that is not recorded in the Company's unaudited consolidated balance sheets. As a result of the Company's continuing involvement with Medallion due to the TA surviving the closing of the Medallion Sale, the Company will record a deferred gain in the amount of its maximum exposure to loss as of October 30, 2017 during the fourth quarter of 2017. This deferred gain will be amortized over the TA's firm commitment transportation term through 2024. See Note 16.a for additional discussion of the Medallion Sale subsequent to September 30, 2017.average composite NGL barrel.
i. Long-lived assets and inventory
Impairment losses are recorded on property and equipment used in operations and other long-lived assets when indicators ofThe following table presents full cost ceiling impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets' carrying amount. Impairment is measured based on the excess of the carrying amount over the fair value of the asset.
Materials and supplies inventory,expense, which is used in the Company's production activities of oil and natural gas properties and midstream service assets, is carried at the lower of cost or net realizable value ("NRV"), with cost determined using the weighted-average cost method, and is included in "Other current assets" and "Other assets, net""Impairment expense" on the unaudited consolidated balance sheets. The NRV for materials and supplies inventory is determined utilizing a replacement cost approach (Level 2).
The Company has frac pit water inventory, which is used in developing oil and natural gas properties and is carried at lower of cost or NRV, with cost determined using the weighted-average cost method, and is included in "Other current assets" on the unaudited consolidated balance sheets. The NRV for frac pit water inventory is determined utilizing a replacement cost approach (Level 2).
The minimum volume of product in a pipeline system that enables the system to operate is known as line-fill and is generally not available to be withdrawn from the pipeline system until the expiration of the transportation contract. The Company owns oil line-fill in third-party pipelines, which is accounted for at lower of cost or NRV, with cost determined using the weighted-average cost method, and is included in "Other assets, net" on the unaudited consolidated balance sheets. The NRV is determined utilizing a quoted market price adjusted for regional price differentials (Level 2).
There were no long-lived asset impairments recorded during the nine months ended September 30, 2017 or 2016. Inventory impairments of $1.0 million were recorded for the nine months ended September 30, 2016. There were no inventory impairments recorded during the nine months ended September 30, 2017.
j.    Debt issuance costs
Debt issuance fees, which are recorded at cost, net of amortization, are amortized over the life of the respective debt agreements utilizing the effective interest and straight-line methods. The Company capitalized $4.7 million of debt issuance costs during the nine months ended September 30, 2017 as a result of entering into the Fifth Amended and Restated Credit Agreement (as amended, the "Senior Secured Credit Facility"). No debt issuance costs were capitalized during the nine months ended September 30, 2016. The Company had total debt issuance costs of $20.4 million and $18.8 million, net of accumulated amortization of $24.4 million and $21.3 million, as of September 30, 2017 and December 31, 2016, respectively.
No debt issuance costs were written off during the nine months ended September 30, 2017. The Company wrote-off $0.8 million of debt issuance costs during the nine months ended September 30, 2016 as a result of changes in the borrowing base and aggregate elected commitment of the Senior Secured Credit Facility, which is included in the unaudited consolidated statements of operations in the "Write-off of debt issuance costs" line item. Debt issuance costs related to the Company's senior unsecured notes are presented in "Long-term debt, net" on the Company's unaudited consolidated balance sheets. Debt issuance costs related to the Senior Secured Credit Facility are presented in "Other assets, net" on the Company's unaudited consolidated balance sheets. See Note 4.f for additional discussion of debt issuance costs.
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Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)


Future amortization expense of debt issuance costs as of September 30, 2017 for the periods presented is as follows:
(in thousands) September 30, 2017
Remaining 2017
$1,044
2018
4,223
2019
4,308
2020
4,396
2021
4,493
Thereafter
1,947
Total
$20,411
k.    Asset retirement obligations
Asset retirement obligations associated with the retirement of tangible long-lived assets are recognized as a liability in the period in which they are incurred and become determinable. The associated asset retirement costs are part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related long-lived asset is charged to expense through depletion, or for midstream service assets through depreciation, of the associated asset. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and as corresponding accretion expense.
The fair value of additions to the asset retirement obligation liability is measured using valuation techniques consistent with the income approach, which converts future cash flows into a single discounted amount. Significant inputs to the valuation include: (i) estimated plug and abandonment cost per well based on Company experience, (ii) estimated remaining life per well, (iii) estimated removal and/or remediation costs for midstream service assets, (iv) estimated remaining life of midstream service assets, (v) future inflation factors and (vi) the Company's average credit adjusted risk-free rate. Inherent in the fair value calculation of asset retirement obligations are numerous assumptions and judgments including, in addition to those noted above, the ultimate settlement of these amounts, the ultimate timing of such settlement and changes in legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing asset retirement obligation liability, a corresponding adjustment will be made to the asset balance.
The Company is obligated by contractual and regulatory requirements to remove certain pipeline and gathering assets and perform other remediation of the sites where such pipeline and gathering assets are located upon the retirement of those assets. However, the fair value of the asset retirement obligation cannot currently be reasonably estimated because the settlement dates are indeterminate. The Company will record an asset retirement obligation for pipeline and gathering assets in the periods in which settlement dates are reasonably determinable.
The following reconciles the Company's asset retirement obligation liability for the periods presented:
Three months ended March 31,
(in thousands)20212020
Full cost ceiling impairment expense$0 $177,182 
Note 6—Debt
(in thousands) Nine months ended September 30, 2017 Year ended December 31, 2016
Liability at beginning of period $52,207
 $46,306
Liabilities added due to acquisitions, drilling, midstream service asset construction and other 492
 1,528
Accretion expense 2,822
 3,483
Liabilities settled upon plugging and abandonment (357) (1,242)
Liabilities removed due to sale of property (871) —
Revision of estimates 178
 2,132
Liability at end of period $54,471
 $52,207
l.    Fair value measurements
The carrying amounts reported in the unaudited consolidated balance sheets for casha.   January 2025 Notes and cash equivalents, accounts receivable, accounts payable, undistributed revenue and royalties, accrued capital expenditures and other accrued assets and liabilities approximate their fair values. See Note 4.e for fair value disclosures related to the Company's debt obligations. The Company carries its derivatives at fair value. See Note 8.a for details regarding the fair value of the Company's derivatives.
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Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)


m.    Treasury stock
Laredo's employees may elect to have the Company withhold shares of stock to satisfy their tax withholding obligations that arise upon the lapse of restrictions on their stock awards. Such treasury stock is recorded at cost and retired upon acquisition.
n.    Compensation awards
Stock-based compensation expense, net of amounts capitalized, is included in "General and administrative" in the unaudited consolidated statements of operations over the awards' vesting periods and is based on the awards' grant date fair value. The Company utilizes the closing stock price on the grant date, less an expected forfeiture rate, to determine the fair values of service vesting restricted stock awards and a Black-Scholes pricing model to determine the fair values of service vesting restricted stock option awards. The Company utilizes a Monte Carlo simulation prepared by an independent third party to determine the fair values of the performance share awards and, in prior periods, the performance unit awards. The Company capitalizes a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration and development of its oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included as an addition to "Oil and natural gas properties" in the unaudited consolidated balance sheets. See Note 5 for further discussion regarding the restricted stock awards, stock option awards, performance share awards and performance unit awards.
o.    July 2016 and May 2016 Equity OfferingsJanuary 2028 Notes
On July 19, 2016, the Company completed the sale of 13,000,000 shares of Laredo's common stock (the "July 2016 Equity Offering") for net proceeds of $136.3 million, after underwriting discounts, commissions and offering expenses. On August 9, 2016, the underwriters exercised their option to purchase an additional 1,950,000 shares of Laredo's common stock, which resulted in net proceeds to the Company of $20.5 million, after underwriting discounts, commissions and offering expenses.
On May 16, 2016, the Company completed the sale of 10,925,000 shares of Laredo's common stock (the "May 2016 Equity Offering") for net proceeds of $119.3 million, after underwriting discounts, commissions and offering expenses. There were no comparative offerings of Laredo's stock during the nine months ended September 30, 2017.
p.    Environmental
The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, among other things, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed in the period incurred. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. Management believes no materially significant liabilities of this nature existed as of September 30, 2017 or December 31, 2016.
q.    Non-cash investing and supplemental cash flow information
The following presents the non-cash investing and supplemental cash flow information for the periods presented:
  Nine months ended September 30,
(in thousands) 2017 2016
Non-cash investing information:    
Change in accrued capital expenditures $39,156
 $(24,963)
Change in accrued capital contribution to equity method investee(1)
 $—
 $(27,583)
Capitalized asset retirement cost $670
 $1,669
Supplemental cash flow information:    
Capitalized interest $756
 $199

(1)See Notes 2.h , 12.a and 16.a for additional discussion of the Company's equity method investee.
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Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)


Note 3—Divestiture and acquisitions
a. 2017 Divestiture of evaluated and unevaluated oil and natural gas properties
In January 2017, the Company completed the sale of 2,900 net acres and working interests in 16 producing vertical wells in the Midland Basin to a third-party buyer for a purchase price of $59.7 million. After transaction costs reflecting an economic effective date of October 1, 2016, the proceeds were $59.5 million, net of working capital and post-closing adjustments. The Company completed the closing adjustments for this divestiture in May 2017. A portion of these proceeds was used to pay down borrowings on the Senior Secured Credit Facility. The purchase price was recorded as an adjustment to oil and natural gas properties pursuant to the rules governing full cost accounting.
Effective at closing, the operations and cash flows of these properties were eliminated from the ongoing operations of the Company, and the Company has no continuing involvement in the properties. This divestiture does not represent a strategic shift and will not have a major effect on the Company's operations or financial results.
b. 2016 Acquisitions of evaluated and unevaluated oil and natural gas properties
The Company accounts for acquisitions of evaluated and unevaluated oil and natural gas properties under the acquisition method of accounting. Accordingly, the Company conducts assessments of net assets acquired and recognizes amounts for identifiable assets acquired and liabilities assumed at the estimated acquisition date fair values, while transaction costs associated with the acquisitions are expensed as incurred.
The Company makes various assumptions in estimating the fair values of assets acquired and liabilities assumed. The most significant assumptions relate to the estimated fair value of evaluated and unevaluated oil and natural gas properties. The fair value of these properties are measured using a discounted cash flow model that converts future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) forecasted oil, NGL and natural gas reserve quantities; (ii) future commodity strip prices as of the closing dates adjusted for transportation and regional price differentials; (iii) forecasted ad valorem taxes, production taxes, income taxes, general and administrative expenses, operating expenses and development costs; and (iv) a peer group weighted-average cost of capital rate subject to additional project-specific risk factors. To compensate for the inherent risk of estimating the value of the unevaluated properties, the discounted future net revenues of proved undeveloped and probable reserves are reduced by additional reserve adjustment factors. These assumptions represent Level 3 inputs under the fair value hierarchy, as described in Note 8.
During the three months ended September 30, 2016, the Company entered into an agreement to acquire 9,200 net acres of additional leasehold interests and working interests in 81 producing vertical wells in western Glasscock and Reagan counties (which included production of 300 net barrels of oil equivalent per day ("BOE/D")) within the Company's core development area for an aggregate purchase price of $125.0 million subject to customary closing adjustments. On July 13 and August 24, 2016, the Company closed on portions of this agreement for $94.4 million and $21.2 million, respectively. The final closing under this agreement occurred in the fourth quarter of 2016 and related to certain remaining interests that were subject to preferential purchase rights that were satisfied subsequent to September 30, 2016.
The following table reflects an aggregate of the final estimate of the fair values of the assets and liabilities acquired during the three months ended September 30, 2016:
(in thousands) Fair value of acquisitions
Fair value of net assets:  
Evaluated oil and natural gas properties $4,800
Unevaluated oil and natural gas properties 110,800
Asset retirement cost 1,105
     Total assets acquired 116,705
Asset retirement obligations (1,105)
        Net assets acquired $115,600
Fair value of consideration paid for net assets:  
Cash consideration $115,600
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Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)


c. Exchange of unevaluated oil and natural gas properties
From time to time, the Company exchanges undeveloped acreage with third parties, with no gain or loss recognized pursuant to the rules governing full cost accounting.
Note 4—Debt
a.   March 2023 Notes
On March 18, 2015,2020, the Company completed an offeringoffer and sale (the "Offering") of $350.0$600.0 million in aggregate principal amount of 69 1/4%2% senior unsecured notes due 20232025 (the "March 2023"January 2025 Notes") and $400.0 million in aggregate principal amount of 10 1/8% senior unsecured notes due 2028 (the "January 2028 Notes"). The March 2023Interest for both the January 2025 Notes will mature on March 15, 2023 and bear an interest rate of 6 1/4% per annum,January 2028 Notes is payable semi-annually, in cash in arrears on MarchJanuary 15 and SeptemberJuly 15 of each year, commencing Septemberyear. The first interest payment was made on July 15, 2015.2020, and consisted of interest from closing to that date. The March 2023terms of the January 2025 Notes and January 2028 Notes include covenants, which are in addition to but different than similar covenants in the Senior Secured Credit Facility, which limit the Company's ability to incur indebtedness, make restricted payments, grant liens and dispose of assets.
The January 2025 Notes and January 2028 Notes are fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain automatic customary releases, including the sale, disposition or transfer of all of the capital stock or of all or substantially all of the assets of a subsidiary guarantor to one or more persons that are not the Company or a restricted subsidiary, exercise of legal defeasance or covenant defeasance options or satisfaction and discharge of the applicable indenture, designation of a subsidiary guarantor as a non-guarantor restricted subsidiary or as an unrestricted subsidiary in accordance with the applicable indenture, release from guarantee under the Senior Secured Credit Facility, or liquidation or dissolution (collectively, the "Releases").
The Company received net proceeds of $982.0 million from the Offering, after deducting underwriting discounts and commissions and estimated offering expenses. The proceeds from the Offering were used (i) to fund Tender Offers (defined below) for the Company's January 2022 Notes and March 2023 Notes are callable by(defined below), (ii) to repay the Company's January 2022 Notes and March 2023 Notes that remained outstanding after settling the Tender Offers and (iii) for general corporate purposes, including repayment of a portion of the borrowings outstanding under the Senior Secured Credit Facility.
In November 2020, the Company's board of directors authorized a $50.0 million bond repurchase program. During the year ended December 31, 2020, the Company beginning March 15, 2018 atrepurchased $22.1 million in aggregate principal amount of the January 2025 Notes and $39.0 million in aggregate principal amount of the January 2028 Notes for aggregate consideration of $13.9 million and $24.2 million, respectively, plus accrued and unpaid interest. The Company recognized a price gain on extinguishment
9
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
of 104.688%$22.3 million related to the difference between the consideration paid and the net carrying amounts of face value with call premiums declining annually to 100%the extinguished portions of face value on March 15, 2021the January 2025 Notes and thereafter.January 2028 Notes.
b.   January 2022 Notes and March 2023 Notes
On January 23, 2014, the Company completed an offering of $450.0 million in aggregate principal amount of 5 5/8% senior unsecured notes due 2022 (the "January 2022 Notes"). The January 2022 Notes willwere due to mature on January 15, 2022 and bearbore an interest rate of 5 5/8% per annum, payable semi-annually, in cash in arrears on January 15 and July 15 of each year, commencing July 15, 2014. The January 2022 Notes arewere fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain Releases. The January 2022 Notes became callable by the Company on January 15, 2017 at a price of 104.219% of face value with call premiums declining annually to 100% of face value on January 15, 2020 and thereafter.
c.    May 2022 Notes
On April 27, 2012,March 18, 2015, the Company completed an offering of $500.0$350.0 million in aggregate principal amount of 7 3/8%6 1/4% senior unsecured notes due 20222023 (the "May 2022"March 2023 Notes"). The May 2022March 2023 Notes willwere due to mature on May 1, 2022March 15, 2023 and bearbore an interest rate of 7 3/8%6 1/4% per annum, payable semi-annually, in cash in arrears on May 1March 15 and November 1September 15 of each year, commencing November 1, 2012.September 15, 2015. The May 2022March 2023 Notes arewere fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain Releases. The May
On January 6, 2020, the Company commenced cash tender offers and consent solicitations for any or all of its outstanding January 2022 Notes became callable byand March 2023 Notes (collectively, the "Tender Offers"). On January 24, 2020 and February 6, 2020, the Company on May 1, 2017settled the Tender Offers for the outstanding principal amounts of $428.9 million and $299.4 million, respectively, for consideration for tender offers and early tender premiums of $431.6 million and $304.1 million for the January 2022 Notes and March 2023 Notes, respectively, plus accrued and unpaid interest. On January 29, 2020, the Company redeemed the remaining $21.1 million of January 2022 Notes not tendered under the Tender Offers at a redemption price of 103.688%100.000% of face value with call premiums declining annually to 100%the principal amount thereof, plus accrued and unpaid interest. On March 15, 2020, the Company redeemed the remaining $50.6 million of face value on May 1, 2020 and thereafter.
See Note 16.c for discussion regardingMarch 2023 Notes not tendered under the commencement ofTender Offers at a redemption price of 101.563% of the outstanding $500.0 million in aggregate principal amount thereof, plus accrued and unpaid interest. The Company recognized a loss on extinguishment of $13.3 million related to the difference between the consideration for tender offers, early tender premiums and redemption prices and the net carrying amounts of the Mayextinguished January 2022 Notes subsequent to September 30, 2017.and March 2023 Notes.
d.c.    Senior Secured Credit Facility
As of September 30, 2017,March 31, 2021, the Senior Secured Credit Facility, which matures on April 19, 2023, had a maximum credit amount of $2.0 billion, a borrowing base and an aggregate elected commitment of $725.0 million each, of $1.0 billion with $155.0$220.0 million outstanding, and was subject to an interest rate of 3.25%2.625%. The Senior Secured Credit Facility has a maturity date of May 2, 2022, provided that if either the January 2022 Notes or May 2022 Notes have not been redeemed or refinanced on or prior to the date 90 days before their respective stated maturity dates (as applicable, the "Early Maturity Date"), the Senior Secured Credit Facility will mature on such Early Maturity Date. The Senior Secured Credit Facility contains both financial and non-financial covenants, all of which the Company was in compliance with as of September 30, 2017. Laredo is required to pay an annual commitment fee on the unused portion of the financial institutions' commitment of 0.375% to 0.5%, based on the ratio of outstanding revolving credit to the total commitment under the Senior Secured Credit Facility.for all periods presented. Additionally, the Senior Secured Credit Facility provides for the issuance of letters of credit, limited to the lesser of total capacity or $20.0 million. No letters$80.0 million. As of March 31, 2021 and December 31, 2020, the Company had one letter of credit were outstanding as of September 30, 2017 or 2016.$44.1 million under the Senior Secured Credit Facility. The Senior Secured Credit Facility is fully and unconditionally guaranteed by LMS and GCM. For additional information see Note 7.c in the 2020 Annual Report. See Note 16.b18.a for discussion of additional borrowingsa borrowing and a payment on and the repayment of the Senior Secured Credit Facility subsequent to September 30, 2017.March 31, 2021.
The Company's measurements of Adjusted EBITDA (non-GAAP) for financial reporting as compared to compliance under its debt agreements differ.
d.    Debt issuance costs
The Company capitalized debt issuance costs of $18.4 million during the three months ended March 31, 2020 in connection with the issuance of the January 2025 Notes and January 2028 Notes. NaN debt issuance costs were capitalized during the three months ended March 31, 2021. The Company wrote off debt issuance costs during the three months ended March 31, 2020 in connection with the extinguishment of the January 2022 Notes and March 2023 Notes, which are included in "Loss on extinguishment of debt" on the unaudited consolidated statement of operations. NaN debt issuance costs were written off during the three months ended March 31, 2021.
The Company had total debt issuance costs of $15.7 million and $17.0 million, net of accumulated amortization of $23.1 million and $22.1 million, as of March 31, 2021 and December 31, 2020, respectively. Debt issuance costs related to the Company's January 2025 and January 2028 Notes are included in "Long-term debt, net" on the unaudited consolidated balance sheets. Debt issuance costs related to the Senior Secured Credit Facility are included in "Other noncurrent assets, net"
10
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)


on the unaudited consolidated balance sheets. Debt issuance costs are amortized on a straight-line basis over the respective terms of the notes and the Senior Secured Credit Facility. See Note 7.e for additional discussion of debt issuance costs.
e.    Long-term debt, net
The following table presents the Company's long-term debt and debt issuance costs, net included in "Long-term debt, net" on the unaudited consolidated balance sheets as of the dates presented:
 March 31, 2021December 31, 2020
(in thousands)Long-term debtDebt issuance costs, netLong-term debt, netLong-term debtDebt issuance costs, netLong-term debt, net
January 2025 Notes577,913 (7,931)569,982 577,913 (8,676)569,237 
January 2028 Notes361,044 (5,652)355,392 361,044 (6,015)355,029 
Senior Secured Credit Facility(1)
220,000 0 220,000 255,000 0 255,000 
Long-term debt, net$1,158,957 $(13,583)$1,145,374 $1,193,957 $(14,691)$1,179,266 

(1)Debt issuance costs, net related to the Senior Secured Credit Facility of $2.1 million and $2.3 million as of March 31, 2021 and December 31, 2020, respectively, are included in "Other noncurrent assets, net" on the unaudited consolidated balance sheets.
Note 7—Stockholders' equity
a.    ATM Program
On October 20, 2017,February 23, 2021, the Company entered into an equity distribution agreement (the "Equity Distribution Agreement") with Wells Fargo Securities, LLC acting as sales agent and/or principal (the "Sales Agent"), pursuant to which the Company may offer and sell, from time to time through the Sales Agent, shares of its common stock, par value $0.01 per share (the "common stock"), having an aggregate gross sales price of up to $75.0 million through an "at-the-market" equity program (the "ATM Program").
Pursuant to the Equity Distribution Agreement, shares of common stock may be offered and sold in privately negotiated transactions or transactions that are deemed to be "at-the-market" offerings as defined in Rule 415 under the Securities Act, including by ordinary brokers’ transactions through the facilities of the New York Stock Exchange, to or through a regular semi-annualmarket maker or as otherwise agreed with the Sales Agent. Under the terms of the Equity Distribution Agreement, the Company may also sell common stock from time to time to the Sales Agent as principal for its own account at a price to be agreed upon at the time of sale. Any sale of common stock to the Sales Agent as principal would be pursuant to the terms of a separate terms agreement between the Company and the Sales Agent, which would be described in a separate prospectus supplement or pricing supplement.
As of March 31, 2021, the Company has sold 723,579 shares of its common stock pursuant to the ATM Program for net proceeds of approximately $26.9 million, after underwriting commissions and other related expenses. Proceeds from the share sales were utilized to reduce borrowings on the Senior Secured Credit Facility. The timing of any additional sales will depend on a variety of factors to be determined by the Company.
b.    Reverse stock split and Authorized Share Reduction
On March 17, 2020, the board of directors authorized an amendment to the Company's amended and restated certificate of incorporation ("Certificate of Incorporation") to effect, at the discretion of the board of directors (i) a reverse stock split that would reduce the number of shares of outstanding common stock in accordance with a ratio to be determined by the board of directors within a range of 1-for-5 and 1-for-20 currently outstanding and (ii) a reduction of the number of authorized shares of common stock by a corresponding proportion ("Authorized Share Reduction").
On May 14, 2020, after receiving stockholder approval of the amendment to the Certificate of Incorporation, the board of directors approved the implementation of the reverse stock split at a ratio of 1-for-20 currently outstanding shares of common stock, and the related corresponding Authorized Share Reduction.
11
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
On June 1, 2020, the amendment to the Certificate of Incorporation became effective and effected the 1-for-20 reverse stock split of the Company's issued and outstanding common stock and the related Authorized Share Reduction from 450,000,000 to 22,500,000 authorized shares, par value $0.01 per share, with authorized shares of preferred stock remaining unchanged at 50,000,000, par value $0.01 per share, for a total of 72,500,000 shares of capital stock. See Note 8 for discussion of the Equity Incentive Plan (defined below), that proportionately reduced the number of shares that may be granted.
c.    Treasury stock
Treasury stock is recorded at cost, which includes incremental direct transaction costs, and is retired upon acquisition as a result of (i) stock exchanged to satisfy tax withholding that arises upon the lapse of restrictions on share-settled equity-based awards at the awardee's election or (ii) stock exchanged for the cost of exercise of stock options at the awardee's election.
Note 8—Equity Incentive Plan
The Laredo Petroleum, Inc. Omnibus Equity Incentive Plan (the "Equity Incentive Plan") provides for the granting of incentive awards in the form of restricted stock awards, stock option awards, performance share awards, outperformance share awards, performance unit awards, phantom unit awards and other awards. On June 1, 2020, in connection with the effectiveness of the reverse stock split and Authorized Share Reduction, the board of directors approved and adopted an amendment to the Equity Incentive Plan to proportionately adjust the limitations on awards that may be granted under the Equity Incentive Plan. Following the amendment, an aggregate of 1,492,500 shares of common stock may be issued under the Equity Incentive Plan. See Note 7.b for additional discussion of the reverse stock split and Authorized Share Reduction.
See Note 9.a in the 2020 Annual Report for additional discussion of the Company's equity-based compensation awards.
a.    Restricted stock awards
Restricted stock awards granted to employees vest on a 33%, 33% and 34% schedule per year beginning on the first anniversary of the grant date and restricted stock awards granted to non-employee directors vest immediately on the grant date.
The following table reflects the restricted stock award activity for the three months ended March 31, 2021:
(in thousands, except for weighted-average grant-date fair value)Restricted stock awardsWeighted-average
grant-date fair value
 (per share)
Outstanding as of December 31, 2020309 $44.88 
Granted188 $34.45 
Forfeited(1)$83.04 
Vested(1)
(103)$65.07 
Outstanding as of March 31, 2021393 $34.50 

(1)The aggregate intrinsic value of vested restricted stock awards for the three months ended March 31, 2021 was $3.5 million.
The Company utilizes the closing stock price on the grant date to determine the fair value of restricted stock awards. As of March 31, 2021, unrecognized equity-based compensation related to the restricted stock awards expected to vest was $11.9 million. Such cost is expected to be recognized over a weighted-average period of 2.18 years.
b.    Stock option awards
As of March 31, 2021, the 11,362 outstanding stock option awards had a weighted-average exercise price of $257.42 per award and a weighted-average remaining contractual term of 3.75 years. There was no activity related to the stock option awards during the three months ended March 31, 2021. The vested and exercisable stock option awards as of March 31, 2021 had 0 intrinsic value.
12
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
c.    Performance share awards
Performance share awards, which the Company has determined are equity awards, are subject to a combination of market, performance and service vesting criteria. For portions of awards with market criteria, a Monte Carlo simulation prepared by an independent third party is utilized to determine the grant-date (or modification date) fair value, and the associated expense is recognized on a straight-line basis over the three-year requisite service period of the awards. For portions of awards with performance criteria, the fair value is equal to the Company's closing stock price on the grant date (or modification date), and for each reporting period, the associated expense fluctuates and is adjusted based on an estimated payout of the number of shares of common stock to be delivered on the payment date for the three-year performance period.
These awards were granted in 2019 and 2018, and their market criteria consists of: (i) the relative three-year total shareholder return ("TSR") comparing the Company's shareholder return to the shareholder return of the peer group specified in each award agreement ("RTSR Performance Percentage") and (ii) the Company's absolute three-year total shareholder return ("ATSR Appreciation"). The performance criteria for these awards consists of the Company's three-year return on average capital employed ("ROACE Percentage"). Any shares earned under performance share awards are expected to be issued in the first quarter following the completion of the respective requisite service periods based on the achievement of certain market and performance criteria, and the payout can range from 0% to 200%.
The following table reflects the performance share award activity for the three months ended March 31, 2021:
(in thousands, except for weighted-average grant-date fair value)
Performance
share awards
Weighted-average
grant-date
fair value
(per share)
Outstanding as of December 31, 202097 $84.06 
Vested(1)
(15)$184.43 
Outstanding as of March 31, 202182 $65.98 

(1)The performance share awards granted on February 16, 2018 had a performance period of January 1, 2018 to December 31, 2020 and, as their market and performance criteria were partially satisfied, resulted in a 43% payout. As such, the granted awards vested and were converted into 6,343 shares of the Company's common stock during the three months ended March 31, 2021 based on this 43% payout.
As of March 31, 2021, unrecognized equity-based compensation related to the performance share awards expected to vest was $2.2 million. Such cost is expected to be recognized over a weighted-average period of 0.92 years. As of March 31, 2021, the expense per performance share, which is the fair value per performance share adjusted for the estimated payout of the performance criteria, was $88.16.
d.    Outperformance share award
An outperformance share award was granted during the year ended December 31, 2019, in conjunction with the appointment of the Company's President, and is accounted for as an equity award. If earned, the payout ranges from 0 to 50,000 shares in the Company's common stock per the vesting schedule. This award is subject to a combination of market and service vesting criteria, therefore, a Monte Carlo simulation prepared by an independent third party was utilized to determine the grant-date fair value with the associated expense recognized over the requisite service period. The payout of this award is based on the highest 50 consecutive trading day average closing stock price of the Company that occurs during the performance period that commenced on June 3, 2019 and ends on June 3, 2022 ("Final Date"). Of the earned outperformance shares, one-third of the award will vest on the Final Date, one-third will vest on the first anniversary of the Final Date and one-third will vest on the second anniversary of the Final Date, provided that the participant has been continuously employed with the Company through the applicable vesting date.
As of March 31, 2021, unrecognized equity-based compensation related to the outperformance share award expected to vest was $0.4 million. Such cost is expected to be recognized over a weighted-average period of 3.25 years.
13
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
e.    Performance unit awards
Performance unit awards, which the Company has determined are liability awards since they are settled in cash, are subject to a combination of market, performance and service vesting criteria. For portions of awards with market criteria, a Monte Carlo simulation prepared by an independent third party is utilized to determine the fair value, and is re-measured at each reporting period until settlement. For portions of awards with performance criteria, the Company's closing stock price is utilized to determine the fair value and is re-measured on the last trading day of each reporting period until settlement and, additionally, the associated expense fluctuates based on an estimated payout for the three-year performance period. The expense related to the performance unit awards is recognized on a straight-line basis over the three-year requisite service period of the awards, and the life-to-date recognized expense is adjusted accordingly at each reporting period based on the quarterly fair value re-measurements and redetermination of the lenders reaffirmedestimated payout for the $1.0 billion borrowing baseperformance criteria.
For performance unit awards granted in 2021, the market criteria consists of: (i) annual relative total shareholder return comparing the Company's shareholder return to the shareholder return of the E&P companies listed in the Russell 2000 index ("Relative TSR") and (ii) annual absolute total shareholder return ("Absolute Return"), together the "PSU Matrix." The performance criteria for these awards consists of: (i) earnings before interest , taxes, depreciation, amortization and exploration expense ("EBITDAX") and three-year total debt reduction (the "EBITDAX/Total Debt Component") and (ii) growth in inventory (the "Inventory Growth Component"). Any units earned are expected to be paid in cash during the first quarter following the completion of the requisite service period, based on the achievement of certain market and performance criteria, and the payout can range from 0% to 250% for the market criteria and 0% to 200% for the performance criteria.
For performance unit awards granted in 2020, the market criteria consists of: (i) the RTSR Performance Percentage and (ii) the ATSR Appreciation. The performance criteria for these awards consists of the ROACE Percentage. Any units earned are expected to be paid in cash during the first quarter following the completion of the requisite service period, based on the achievement of certain market and performance criteria, and the payout can range from 0% to 200%, but is capped at 100% if the ATSR Appreciation is zero or less.

The following table presents the assumptions used to estimate the fair value per performance unit for the performance unit awards granted in 2021:
March 9, 2021
Remaining performance period2.81 years
Risk-free interest rate(1)
0.32 %
Dividend yield0 %
Expected volatility(2)
114.60 %
Closing stock price on grant date$34.66 

(1)The remaining performance period matched zero-coupon risk-free interest rate was derived from the U.S. Treasury constant maturities yield curve on grant date.
(2)The Company utilized its own remaining performance period matched historical volatility in order to develop the expected volatility.
The following table reflects the performance unit award activity for the three months ended March 31, 2021:
(in thousands)Performance units
Outstanding as of December 31, 202099 
Granted110 
Outstanding as of March 31, 2021209 
14
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
As of March 31, 2021, unrecognized equity-based compensation related to the performance unit awards expected to vest was $7.0 million. Such cost is expected to be recognized over a weighted-average period of 2.62 years. As of March 31, 2021, the expense per performance unit, which is the fair value per performance unit adjusted for the estimated payout of the performance criteria, for the 2021 and 2020 performance unit awards was $39.77 and $41.82, respectively.
f.    Phantom unit awards
Phantom unit awards, which the Company has determined are liability awards, represent the holder's right to receive the cash equivalent of one share of common stock of the Company for each phantom unit as of the applicable vesting date, subject to withholding requirements. Phantom unit awards granted to employees vest 33%, 33% and 34% per year beginning on the first anniversary of the grant date.
The following table reflects the phantom unit award activity for the three months ended March 31, 2021:
(in thousands, except for weighted-average fair value)Phantom units
Outstanding as of December 31, 202075 
Granted5 
Vested(1)
(25)
Outstanding as of March 31, 202155 

(1)On March 5, 2021, the vested phantom unit awards were settled and paid out in cash at a fair value of $34.24 based on the Company's closing stock price on the vesting date.
The Company utilizes the closing stock price on the last day of each reporting period to determine the fair value of phantom unit awards and the life-to-date recognized expense is adjusted accordingly. As of March 31, 2021, unrecognized equity-based compensation related to the phantom unit awards expected to vest was $1.6 million. Such cost is expected to be recognized over a weighted-average period of 2.08 years.
g.    Equity-based compensation
The following table reflects equity-based compensation expense for the periods presented:
Three months ended March 31,
(in thousands)20212020
Equity awards:
Restricted stock awards$1,963 $2,498 
Performance share awards725 756 
Outperformance share award43 44 
Stock option awards7 43 
Total share-settled equity-based compensation, gross$2,738 $3,341 
Less amounts capitalized(670)(965)
Total share-settled equity-based compensation, net$2,068 $2,376 
Liability awards:
Performance unit awards$820 $24 
Phantom unit awards506 25 
Total cash-settled equity-based compensation, gross$1,326 $49 
Less amounts capitalized(198)(10)
Total cash-settled equity-based compensation, net$1,128 $39 
Total equity-based compensation, net$3,196 $2,415 
15
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
Note 9—Derivatives
The Company has 3 types of derivative instruments as of March 31, 2021: (i) commodity derivatives, (ii) a debt interest rate derivative and (iii) a contingent consideration derivative. See Notes (i) 2.e in the 2020 Annual Report for the Company's significant accounting policies for derivatives and presentation, (ii) 10.a for fair value measurement of derivatives on a recurring basis and (iii) 18.b for derivatives subsequent events. The Company's derivatives were not designated as hedges for accounting purposes, and the Company does not enter into such instruments for speculative trading purposes. Accordingly, the changes in fair value are recognized in "Gain (loss) on derivatives, net" under "Non-operating income (expense)" on the unaudited consolidated statements of operations.
The following table summarizes components of the Company's gain (loss) on derivatives, net by type of derivative instrument for the periods presented:
Three months ended March 31,
(in thousands)20212020
Commodity$(154,033)$291,361 
Interest rate4 0 
Contingent consideration(336)6,475 
Gain (loss) on derivatives, net$(154,365)$297,836 
a.    Commodity
Due to the inherent volatility in oil, NGL and natural gas prices and differences in the prices of oil, NGL and natural gas between where the Company produces and where the Company sells such commodities, the Company engages in commodity derivative transactions, such as puts, swaps, collars and basis swaps, to hedge price risk associated with a portion of the Company's anticipated sales volumes. By removing a portion of the price volatility associated with future sales volumes, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flows from operations. See Note 9 in the 2020 Annual Report for discussion of transaction types and settlement indexes.
During the three months ended March 31, 2021, the Company’s derivatives were settled based on reported prices on commodity exchanges, with (i) oil derivatives settled based on Brent ICE pricing, (ii) NGL derivatives settled based on Mont Belvieu OPIS pricing and (iii) natural gas derivatives settled based on Henry Hub NYMEX and Waha Inside FERC pricing.
During the three months ended March 31, 2021, the Company completed a hedge restructuring by (i) selling 2,254,500 calendar year 2021 $55.00 per barrel Brent ICE puts, which volumetrically offset existing calendar year 2021 $55.00 per barrel Brent ICE puts, and receiving aggregate premiums of $9.0 million at inception of the contracts and (ii) entering into 2,254,500 calendar year 2021 Brent ICE swaps at a weighted-average price of $55.09 per barrel. Associated with the aforementioned existing calendar year 2021 $55.00 per barrel Brent ICE puts, which were entered into during 2020, were $50.6 million in aggregate premiums paid at the inception of the contacts.
During the three months ended March 31, 2020, the Company completed a hedge restructuring by early terminating collars and entering into new swaps. The following table presents the commodity derivatives that were terminated:
Aggregate volumes (Bbl)Floor price ($/Bbl)Ceiling price ($/Bbl)Contract period
WTI NYMEX - Collars912,500 $45.00 $71.00 January 2021 - December 2021
16
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
The following table summarizes open commodity derivative positions as of March 31, 2021, for commodity derivatives that were entered into through March 31, 2021, for the settlement periods presented:
 Remaining Year 2021Year 2022
Oil: 
Brent ICE - Swaps:
Volume (Bbl)5,651,250 3,759,500 
Weighted-average price ($/Bbl)$51.29 $47.05 
Brent ICE - Collars: 
Volume (Bbl)440,000 821,250 
Weighted-average floor price ($/Bbl)$45.00 $53.67 
Weighted-average ceiling price ($/Bbl)$59.50 $62.40 
Total Brent ICE:
Total volume (Bbl)6,091,250 4,580,750 
Weighted-average floor price ($/Bbl)$50.83 $48.24 
Weighted-average ceiling price ($/Bbl)$51.88 $49.81 
NGL:
Mont Belvieu OPIS:
Purity Ethane - Swaps:
Volume (Bbl)687,500 0 
Weighted-average price ($/Bbl)$12.01 $0 
Non-TET Propane - Swaps:
Volume (Bbl)1,825,725 0 
Weighted-average price ($/Bbl)$22.90 $0 
Non-TET Normal Butane - Swaps:
Volume (Bbl)608,575 0 
Weighted-average price ($/Bbl)$25.87 $0 
Non-TET Isobutane - Swaps:
Volume (Bbl)166,100 0 
Weighted-average price ($/Bbl)$26.55 $0 
Non-TET Natural Gasoline - Swaps:
Volume (Bbl)663,850 0 
Weighted-average price ($/Bbl)$38.16 $0 
Total NGL volume (Bbl)3,951,750 0 
Natural gas: 
Henry Hub NYMEX - Swaps: 
Volume (MMBtu)32,037,500 3,650,000 
Weighted-average price ($/MMBtu)$2.59 $2.73 
Waha Inside FERC to Henry Hub NYMEX - Basis Swaps: 
Volume (MMBtu)42,680,000 18,067,500 
Weighted-average differential ($/MMBtu)$(0.47)$(0.41)


17
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
b.    Interest rate
Due to the inherent volatility in interest rates, the Company has entered into an interest rate derivative swap to hedge interest rate risk associated with a portion of the Company's anticipated outstanding debt under the Senior Secured Credit Facility. The Company will pay a fixed rate over the contract term for that portion. By removing a portion of the interest rate volatility associated with anticipated outstanding debt, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flows from operations.
The following table summarizes the Company's aggregate elected commitmentinterest rate derivative:
Notional amount
(in thousands)		Fixed rateContract period
LIBOR - Swap$100,000 0.345 %April 16, 2020 - April 18, 2022
c.    Contingent consideration
The Company's asset acquisition of $1.0 billion remained unchanged.oil and natural gas properties that closed on April 30, 2020 provides for potential contingent payments to be paid by the Company if the arithmetic average of the monthly settlement WTI NYMEX prices exceed certain thresholds for the contingency period beginning on January 1, 2021 and ending on the earlier of December 31, 2022 or the date the counterparty has received the maximum consideration of $1.2 million. See Note 3.a for further discussion of the Company's asset acquisition associated with potential contingent consideration payments. At each quarterly reporting period, the Company remeasures its contingent consideration with the changes in fair values recognized in earnings.
18
e.    
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
Note 10—Fair value measurements
See the beginning of debtNote 11 in the 2020 Annual Report for information about the fair value hierarchy levels.
a.    Fair value measurement on a recurring basis
See Note 9 for further discussion of the Company's derivatives, and see Note 2.e in the 2020 Annual Report for the Company's significant accounting policies for derivatives.
Balance sheet presentation
The following tables present the Company's derivatives by (i) balance sheet classification, (ii) derivative type and (iii) fair value hierarchy level, and provide a total, on a gross basis and a net basis reflected in "Derivatives" on the unaudited consolidated balance sheets as of the dates presented:
March 31, 2021
(in thousands)Level 1Level 2Level 3Total gross fair valueAmounts offsetNet fair value presented on the unaudited consolidated balance sheets
Assets:
Current:
Commodity - Oil$0 $6,197 $0 $6,197 $(6,197)$0 
Commodity - NGL0 1,735 0 1,735 (1,735)0 
Commodity - Natural gas0 (195)0 (195)195 0 
Noncurrent:
Commodity - Oil$0 $3,928 $0 $3,928 $(3,928)$0 
Commodity - NGL0 0 0 0 0 0 
Commodity - Natural gas0 545 0 545 (545)0 
Liabilities:
Current:
Commodity - Oil$0 $(73,960)$0 $(73,960)$6,197 $(67,763)
Commodity - NGL0 (39,133)0 (39,133)1,735 (37,398)
Commodity - Natural gas0 (21,726)0 (21,726)(195)(21,921)
Interest rate - LIBOR0 (197)0 (197)0 (197)
Contingent consideration0 (1,115)0 (1,115)0 (1,115)
Noncurrent:
Commodity - Oil$0 $(32,534)$0 $(32,534)$3,928 $(28,606)
Commodity - NGL0 0 0 0 0 0 
Commodity - Natural gas0 (1,746)0 (1,746)545 (1,201)
Interest rate - LIBOR0 (13)0 (13)0 (13)
Contingent consideration0 (1)0 (1)0 (1)
Net derivative liability positions$0 $(158,215)$0 $(158,215)$— $(158,215)
19
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
December 31, 2020
(in thousands)Level 1Level 2Level 3Total gross fair valueAmounts offsetNet fair value presented on the
consolidated balance sheets
Assets:
Current:
Commodity - Oil$0 $32,958 $0 $32,958 $(24,930)$8,028 
Commodity - NGL0 2,720 0 2,720 (2,720)0 
Commodity - Natural gas0 521 0 521 (656)(135)
Noncurrent:
Commodity - Oil$0 $0 $0 $0 $0 $0 
Commodity - NGL0 0 0 0 0 0 
Commodity - Natural gas0 535 0 535 (535)0 
Liabilities:
Current:
Commodity - Oil$0 $(25,118)$0 $(25,118)$24,930 $(188)
Commodity - NGL0 (16,185)0 (16,185)2,720 (13,465)
Commodity - Natural gas0 (17,958)0 (17,958)656 (17,302)
Interest rate - LIBOR0 (206)0 (206)0 (206)
Contingent consideration0 (665)0 (665)0 (665)
Noncurrent:
Commodity - Oil$0 $(10,932)$0 $(10,932)$0 $(10,932)
Commodity - NGL0 0 0 0 0 0 
Commodity - Natural gas0 (1,476)0 (1,476)535 (941)
Interest rate - LIBOR0 (63)0 (63)0 (63)
Contingent consideration0 (115)0 (115)0 (115)
Net derivative liability positions$0 $(35,984)$0 $(35,984)$— $(35,984)
See Note 11.a in the 2020 Annual Report for discussion of the significant Level 2 inputs used in the fair value mark-to-market analysis of commodity, interest rate and contingent consideration derivatives. The Company reviewed the third-party specialist's valuations of commodity, interest rate and contingent consideration derivatives, including the related inputs, and analyzed changes in fair values between reporting dates.
The Company's acquisition of oil and natural gas properties that closed on April 30, 2020 provides for potential contingent payments to be paid by the Company. The fair value of the contingent consideration derivative liability was $1.1 million and $0.8 million as of March 31, 2021 and December 31, 2020, respectively. See Note 3.a for further discussion of the Company's asset acquisition associated with the potential contingent consideration payments.
b.    Fair value measurement on a nonrecurring basis
See Note 2.i in the 2020 Annual Report for the Level 2 fair value hierarchy input assumptions used in estimating the net realizable value ("NRV") of inventory used to determine the $1.3 million impairment expense of inventory recorded during the three months ended March 31, 2020, pertaining to line-fill and other inventories. There were 0 impairments of inventory recorded during the three months ended March 31, 2021.
See Note 11.b in the 2020 Annual Report for the Level 3 fair value hierarchy input assumptions used in the fair value measurement of long-lived assets used to determine the $8.2 million impairment expense of long-lived assets recorded during the three months ended March 31, 2020, pertaining to midstream service assets. There were 0 impairments of long-lived assets recorded during the three months ended March 31, 2021.
20
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
c.    Items not accounted for at fair value
The carrying amounts reported on the unaudited consolidated balance sheets for cash and cash equivalents, accounts receivable, accounts payable, accrued capital expenditures, undistributed revenue and royalties and other accrued assets and liabilities approximate their fair values.
The Company has not elected to account for its debt instruments at fair value. The following table presents the carrying amounts and fair values of the Company's debt as of the dates presented:
 September 30, 2017 December 31, 2016 March 31, 2021December 31, 2020
(in thousands) Long-term
debt		 
Fair
value
 Long-term
debt		 
Fair
value
(in thousands)Long-term
debt
Fair
value(1)
Long-term
debt
Fair
value(1)
January 2022 Notes $450,000
 $457,110
 $450,000
 $456,382
May 2022 Notes 500,000
 520,625
 500,000
 521,413
March 2023 Notes 350,000
 363,342
 350,000
 365,649
January 2025 NotesJanuary 2025 Notes$577,913 $556,288 $577,913 $499,299 
January 2028 NotesJanuary 2028 Notes361,044 346,064 361,044 299,667 
Senior Secured Credit Facility 155,000
 155,035
 70,000
 69,975
Senior Secured Credit Facility220,000 220,130 255,000 255,187 
Total $1,455,000
 $1,496,112
 $1,370,000
 $1,413,419
Total$1,158,957 $1,122,482 $1,193,957 $1,054,153 

(1)The fair values of the debt outstanding on the January 2022 Notes, the May 2022 Notes and the March 2023 Notesnotes were determined using the September 30, 2017Level 1 fair value hierarchy quoted market prices for each respective instrument as of March 31, 2021 and December 31, 2016 quoted market price (Level 1) for each respective instrument.2020. The fair values of the outstanding debt onunder the Senior Secured Credit Facility were estimated utilizing the Level 2 fair value hierarchy pricing model for similar instruments as of September 30, 2017March 31, 2021 and December 31, 2016 were estimated utilizing pricing models for similar instruments (Level 2). See Note 8 for information about fair value hierarchy levels.2020.
f.    Long-term debt, net
The following table summarizes the net presentation of the Company's long-term debt and debt issuance costs on the unaudited consolidated balance sheets as of the dates presented:
  September 30, 2017 December 31, 2016
(in thousands) Long-term debt Debt issuance costs, net Long-term debt, net Long-term debt Debt issuance costs, net Long-term debt, net
January 2022 Notes $450,000
 $(4,230) $445,770
 $450,000
 $(4,963) $445,037
May 2022 Notes 500,000
 (5,442) 494,558
 500,000
 (6,164) 493,836
March 2023 Notes 350,000
 (4,360) 345,640
 350,000
 (4,964) 345,036
Senior Secured Credit Facility(1)
 155,000
 —
 155,000
 70,000
 —
 70,000
Total $1,455,000
 $(14,032) $1,440,968
 $1,370,000
 $(16,091) $1,353,909

(1)Debt issuance costs, net related to our Senior Secured Credit Facility of $6.4 million and $2.7 million as of September 30, 2017 and December 31, 2016, respectively, are reported in "Other assets, net" on the unaudited consolidated balance sheets.
Note 5—Employee compensation
The Company has a Long-Term Incentive Plan (the "LTIP"), which provides for the granting of incentive awards in the form of restricted stock awards, stock option awards, performance share awards, performance unit awards and other awards. The LTIP provides for the issuance of up to 24,350,000 shares of Laredo's common stock.
The Company recognizes the fair value of stock-based compensation awards expected to vest over the requisite service period as a charge against earnings, net of amounts capitalized. The Company's stock-based compensation awards are accounted for as equity instruments, and in prior periods, its performance unit awards were accounted for as liability awards. Stock-based compensation is included in "General and administrative" in the unaudited consolidated statements of operations. The Company capitalizes a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration and development of oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included as an addition to "Oil and natural gas properties" in the unaudited consolidated balance sheets.
Table of Contents
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)


a.    Restricted stock awards
All service vesting restricted stock awards are treated as issued and outstanding in the accompanying unaudited consolidated financial statements. Per the award agreement terms, if an employee terminates employment prior to the restriction lapse date for reasons other than death or disability, the awarded shares are forfeited and canceled and are no longer considered issued and outstanding. If the employee's termination of employment is by reason of death or disability, all of the holder's restricted stock will automatically vest. Historically, restricted stock awards granted to officers and employees vest in a variety of vesting schedules including (i) 33%, 33% and 34% per year beginning on the first anniversary date of the grant, (ii) fully on the first anniversary of the grant date and (iii) fully on the third anniversary of the grant date. Beginning August 2017, stock awards granted to non-employee directors vest immediately upon the grant date. Restricted stock awards granted to non-employee directors prior to August 2017 vest on the first anniversary of the grant date.
The following table reflects the restricted stock award activity for the nine months ended September 30, 2017:
(in thousands, except for weighted-average grant date fair values) 
Restricted
stock
awards
 
Weighted-average
grant date fair value
(per award)
Outstanding as of December 31, 2016 3,878
 $12.88
Granted 1,213
 $13.92
Forfeited (264) $12.88
Vested(1)
 (1,618) $13.78
Outstanding as of September 30, 2017 3,209
 $12.82

(1)The total intrinsic value of vested restricted stock awards for the nine months ended September 30, 2017 was $22.5 million.
The Company utilizes the closing stock price on the grant date to determine the fair value of service vesting restricted stock awards. As of September 30, 2017, unrecognized stock-based compensation related to the restricted stock awards expected to vest was $26.7 million. Such cost is expected to be recognized over a weighted-average period of 1.73 years.
b.    Stock option awards
Stock option awards granted under the LTIP vest and become exercisable in four equal installments on each of the four annual anniversaries of the grant date. The following table reflects the stock option award activity for the nine months ended September 30, 2017:
(in thousands, except for weighted-average exercise price and 
weighted-average remaining contractual term)
 
Stock 
option
awards
 Weighted-average
 exercise price
(per award)		 Weighted-average
remaining contractual term
(years)
Outstanding as of December 31, 2016 2,370
 $12.54
 7.71
Granted 391
 $14.12
 
Exercised(1)
 (44) $8.17
 
Expired or canceled (57) $20.58
 
Outstanding as of September 30, 2017 2,660
 $12.67
 7.37
Vested and exercisable as of September 30, 2017(2)
 1,273
 $16.38
 6.22
Expected to vest as of September 30, 2017(3)
 1,387
 $9.26
 8.42

(1)The total intrinsic value of exercised stock option awards for the nine months ended September 30, 2017 was $0.3 million.
(2)The vested and exercisable stock option awards as of September 30, 2017 had an aggregate intrinsic value of $2.1 million.
(3)The stock option awards expected to vest as of September 30, 2017 had an aggregate intrinsic value of $6.3 million.
The Company utilizes the Black-Scholes option pricing model to determine the fair value of stock option awards and recognizes the associated expense on a straight-line basis over the four-year requisite service period of the awards. Determining
Table of Contents
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)


the fair value of equity-based awards requires judgment, including estimating the expected term that stock option awards will be outstanding prior to exercise and the associated expected volatility. As of September 30, 2017, unrecognized stock-based compensation related to stock option awards expected to vest was $9.4 million. Such cost is expected to be recognized over a weighted-average period of 2.52 years.
The assumptions used to estimate the fair value of the 390,733 stock option awards granted during the nine months ended September 30, 2017 are as follows:
  Granted on
February 17, 2017
Risk-free interest rate(1)
 2.14%
Expected option life(2)
 6.25 years
Expected volatility(3)
 60.84%
Fair value per stock option award $8.22

(1)U.S. Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, correlating the treasury yield terms to the expected life of the stock option award.
(2)As the Company had limited exercise history at the time of valuation relating to terminations and modifications, expected stock option award life assumptions were developed using the simplified method in accordance with GAAP.
(3)The Company utilized its own historical volatility in order to develop the expected volatility.     
In accordance with the LTIP and stock option agreement, the stock option awards granted will become exercisable in accordance with the following schedule based upon the number of full years of the optionee's continuous employment or service with the Company, following the date of grant:
Full years of continuous employment Incremental percentage of
option exercisable		 Cumulative percentage of
option exercisable
Less than one —% —%
One 25% 25%
Two 25% 50%
Three 25% 75%
Four 25% 100%
No shares of common stock may be purchased unless the optionee has remained in continuous employment with the Company for one year from the grant date. Unless terminated sooner, the stock option award will expire if and to the extent it is not exercised within 10 years from the grant date. The unvested portion of a stock option award shall expire upon termination of employment, and the vested portion of a stock option award shall remain exercisable for (i) one year following termination of employment by reason of the holder's death or disability, but not later than the expiration of the option period, or (ii) 90 days following termination of employment for any reason other than the holder's death or disability, and other than the holder's termination of employment for cause. Both the unvested and the vested but unexercised portion of a stock option award shall expire upon the termination of the option holder's employment or service by the Company for cause.
c.    Performance share awards
Performance share awards granted to management are subject to a combination of market and service vesting criteria. A Monte Carlo simulation prepared by an independent third party is utilized to determine the grant date fair value of these awards. The Company has determined these awards are equity awards and recognizes the associated expense on a straight-line basis over the three-year requisite service period of the awards. Any shares earned under such awards are expected to be issued in the first quarter following the completion of the requisite service period based on the achievement of certain performance criteria.    
Table of Contents
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)


The following table reflects the performance share award activity for the nine months ended September 30, 2017:
(in thousands, except for weighted-average grant date fair values) 
Performance
share
awards
 
Weighted-average
grant date fair value
(per award)
Outstanding as of December 31, 2016 2,325
 $18.35
Granted 696
 $18.96
Forfeited (67) $18.12
Vested(1)
 (200) $28.56
Outstanding as of September 30, 2017 2,754
 $17.77

(1)These performance share awards had a performance period of January 1, 2014 to December 31, 2016 and, as their vesting and performance criteria were satisfied, each award converted into 0.75 shares representing 150,388 shares of common stock issued during the first quarter of 2017.
As of September 30, 2017, unrecognized stock-based compensation related to the performance share awards expected to vest was $25.2 million. Such cost is expected to be recognized over a weighted-average period of 1.77 years.
The assumptions used to estimate the fair values of the 696,460 performance share awards granted during the nine months ended September 30, 2017 are as follows:
  Granted on
February 17, 2017
Risk-free interest rate(1)
 1.44%
Dividend yield —%
Expected volatility(2)
 74.00%
Laredo stock closing price on grant date $14.12
Fair value per performance share award $18.96

(1)The risk-free interest rate was derived using a term-matched zero-coupon yield derived from the U.S. Treasury constant maturities yield curve on the grant date.
(2)The Company utilized its own historical volatility in order to develop the expected volatility.
d.    Stock-based compensation expense
The following has been recorded to stock-based compensation expense for the periods presented:
  Three months ended September 30, Nine months ended September 30,
(in thousands) 2017 2016 2017 2016
Restricted stock award compensation $5,422
 $6,540
 $16,856
 $15,000
Stock option award compensation 1,159
 1,653
 3,600
 3,054
Performance share award compensation 4,255
 3,450
 12,063
 5,271
Total stock-based compensation, gross 10,836
 11,643
 32,519
 23,325
Less amounts capitalized in oil and natural gas properties (1,870) (1,992) (5,642) (3,763)
Total stock-based compensation, net of amounts capitalized $8,966
 $9,651
 $26,877
 $19,562
e.    Performance unit awards
The performance unit awards issued to management on February 15, 2013 (the "2013 Performance Unit Awards") were subject to a combination of market and service vesting criteria. These awards were accounted for as liability awards as they were settled in cash at the end of the requisite service period based on the achievement of certain performance criteria.
The 44,481 settled 2013 Performance Unit Awards had a performance period of January 1, 2013 to December 31, 2015 and, as their vesting and performance criteria were satisfied, they were paid at $143.75 per unit during the first quarter of 2016.
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Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)


Note 6—Income taxes
The Company is subject to federal and state income taxes and the Texas franchise tax. The Company had federal net operating loss carry-forwards totaling $1.9 billion and state of Oklahoma net operating loss carry-forwards totaling $41.2 million as of September 30, 2017. These carry-forwards begin expiring in 2026. As of September 30, 2017, the Company believes a portion of the net operating loss carry-forwards are not fully realizable. The Company considered all available evidence, both positive and negative, in determining whether, based on the weight of that evidence, a valuation allowance was needed. Such consideration included projected future cash flows from its oil, NGL and natural gas reserves (including the timing of those cash flows), the reversal of deferred tax liabilities recorded as of September 30, 2017, the Company's ability to capitalize intangible drilling costs, rather than expensing these costs in order to prevent an operating loss carry-forward from expiring unused, and future projections of Oklahoma sourced income. As of September 30, 2017, a full valuation allowance of $712.2 million has been recorded against the Company's deferred tax position.
Note 7—Derivatives
a. Derivatives
The Company engages in derivative transactions such as puts, swaps, collars, basis swaps and call spreads to hedge price risks due to unfavorable changes in oil, NGL and natural gas prices related to its production. As of September 30, 2017, the Company had 44 open derivative contracts with financial institutions that extend from October 2017 to December 2019. None of these contracts were designated as hedges for accounting purposes. The contracts are recorded at fair value on the unaudited consolidated balance sheets and gains and losses are recognized in earnings. Gains and losses on derivatives are reported in the unaudited consolidated statements of operations in the "Gain (loss) on derivatives, net" line item.
Each put transaction has an established floor price. The Company pays its counterparty a premium, which can be paid at inception or deferred until settlement, to enter into the put transaction. When the settlement price is below the floor price, the counterparty pays the Company an amount equal to the difference between the settlement price and the floor price multiplied by the hedged contract volume. When the settlement price is at or above the floor price in an individual month in the contract period, the put option expires with no settlement for that particular month, except with regard to the deferred premium if any.
Each swap transaction has an established fixed price. When the settlement price is below the fixed price, the counterparty pays the Company an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the fixed price, the Company pays its counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume.
Each collar transaction has an established price floor and ceiling. Depending on the terms, the Company may pay its counterparty a premium, which can be paid at inception or deferred until settlement. When the settlement price is below the price floor established by these collars, the counterparty pays the Company an amount equal to the difference between the settlement price and the price floor multiplied by the hedged contract volume. When the settlement price is above the price ceiling established by these collars, the Company pays its counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the hedged contract volume. When the settlement price is between the price floor and price ceiling established by these collars in an individual month in the contract period, the collar expires with no settlement paid by either the Company or the counterparty for that particular month, except with regard to the deferred premium, if any.
Each basis swap transaction has an established fixed basis differential corresponding to two floating index prices. Depending on the difference of the two floating index prices in relationship to the fixed basis differential, the Company either receives an amount from its counterparty, or pays an amount to its counterparty, equal to the difference multiplied by the hedged contract volume.
Each call spread transaction has an established short call price and long call price. Depending on the terms, the counterparty may pay a premium to the Company to enter into the transaction. When the settlement price is above the short call price up to the long call price, the Company pays its counterparty an amount equal to the difference between the settlement price and the short call price multiplied by the hedged contract volume. When the settlement price is above the long call price, the Company pays the counterparty an amount equal to the difference between the long call price and the short call price multiplied by the hedged contract volume. When the settlement price is at or below the short call price in an individual month in the contract period, the call option expires with no settlement paid by either the Company or the counterparty for that particular month, except with regard to the deferred premium, if any.
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Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)


Other than the oil basis swaps, the Company's oil derivatives are settled based on the month's average daily NYMEX index price for the first nearby month of the West Texas Intermediate Light Sweet Crude Oil Futures Contract. The oil basis swaps are settled based on the swaps' differential between the Argus Americas Crude West Texas Intermediate ("WTI") index prices for WTI Midland-weighted average and WTI Cushing-WTI formula basis price less the differential price for the trade month. The Company's NGL derivatives are settled based on the month's average daily OPIS index price for Mont Belvieu Purity Ethane and TET Propane. The Company's natural gas derivatives are settled based on the Inside FERC index price for West Texas WAHA for the calculation period.
During the nine months ended September 30, 2017, the Company completed a hedge restructuring by early terminating a swap that resulted in a termination amount to the Company of $4.2 million that was settled in full by applying the proceeds to pay the premium on one new collar entered into during the hedge restructuring. The following details the derivative that was terminated:
  Aggregate volumes (Bbl) Floor price ($/Bbl) Ceiling price ($/Bbl) Contract period
Oil swap 1,095,000
 $52.12
 $52.12
 January 2018 - December 2018
During the nine months ended September 30, 2016, the Company completed a hedge restructuring by early terminating the floors of certain derivative contract collars that resulted in a termination amount to the Company of $80 million, which was settled in full by applying the proceeds to pay the premiums on two new derivatives entered into during the hedge restructuring.
During the nine months ended September 30, 2017, the following derivatives were entered into:
  
Aggregate volumes(1)
 
Floor price(2)
 
Ceiling price(2)
 
Short call price(2)
 
Long call price(2)
 
Differential price(2)
 Contract period
Oil(3):
  
            
Call spread(4)
 1,140,800
 $—
 $—
 $60.00
 $100.00
 $—
      July 2017 - December 2017
Call spread(5)
 184,000
 $—
 $—
 $60.00
 $80.00
 $—
      July 2017 - December 2017
Put(6)
 4,378,000
 $50.00
 $—
 $—
 $—
 $—
 January 2018 - December 2018
Collar 584,000
 $50.00
 $60.00
 $—
 $—
 $—
 January 2018 - December 2018
Collar(7)
 3,504,000
 $40.00
 $60.00
 $—
 $—
 $—
 January 2018 - December 2018
Basis swap 1,825,000
 $—
 $—
 $—
 $—
 $(0.59) January 2018 - December 2018
Basis swap 365,000
 $—
 $—
 $—
 $—
 $(0.58) January 2018 - December 2018
Basis swap 730,000
 $—
 $—
 $—
 $—
 $(0.52) January 2018 - December 2018
Basis swap 730,000
 $—
 $—
 $—
 $—
 $(0.49) January 2018 - December 2018
Put 730,000
 $50.00
 $—
 $—
 $—
 $—
 January 2019 - December 2019
Natural gas:              
Collar(8)
 10,950,000
 $2.50
 $3.25
 $—
 $—
 $—
 January 2018 - December 2018

(1)Oil is in Bbl and natural gas is in MMBtu.
(2)Oil is in $/Bbl and natural gas is in $/MMBtu.
(3)There are $22.9 million in deferred premiums associated with these contracts.
(4)A premium of $0.5 million was settled in full at inception by applying the proceeds to pay the premiums on a put entered into simultaneously.
(5)A premium of $0.1 million was settled in full at inception by applying the proceeds to pay the premiums on a put entered into simultaneously.
(6)Premiums of $4.9 million were paid at inception, of which $0.6 million were settled in full at inception by applying the proceeds from the call spreads entered into simultaneously.
(7)A premium of $4.2 million was settled in full at inception as part of the Company's 2017 hedge restructuring by applying the proceeds of the terminated swap.
(8)There are $0.9 million in deferred premiums associated with these contracts.
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Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)



The following represents cash settlements received for derivatives, net for the periods presented:
  Three months ended September 30, Nine months ended September 30,
(in thousands) 2017 2016 2017 2016
Cash settlements received for matured derivatives, net(1)
 $13,635
 $44,307
 $34,791
 $157,626
Cash settlements received for early terminations of derivatives, net(2)
 —
 —
 4,234
 80,000
Cash settlements received for derivatives, net $13,635
 $44,307
 $39,025
 $237,626

(1)The settlement amounts do not include premiums paid attributable to contracts that matured during the respective period.
(2)The settlement amount for the nine months ended September 30, 2016 includes $4.0 million in deferred premiums that were settled net with the early terminated contracts from which they originated.
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Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)



The following table summarizes open positions as of September 30, 2017, and represents, as of such date, derivatives in place through December 2019 on annual production:
  
Remaining year
2017
 Year
2018		 Year
2019
Oil positions:    
  
Puts:  
  
  
Hedged volume (Bbl) 264,500
 5,427,375
 730,000
Weighted-average price ($/Bbl) $60.00
 $51.93
 $50.00
Swaps:  
  
  
Hedged volume (Bbl) 506,000
 —
 —
Weighted-average price ($/Bbl) $51.54
 $—
 $—
Collars:  
  
  
Hedged volume (Bbl) 956,800
 4,088,000
 —
Weighted-average floor price ($/Bbl) $56.92
 $41.43
 $—
Weighted-average ceiling price ($/Bbl) $86.00
 $60.00
 $—
Call Spreads:      
Hedged volume (Bbl) 662,400
 —
 —
Weighted-average short call price ($/Bbl) $60.00
 $—
 $—
Weighted-average long call price ($/Bbl) $97.22
 $—
 $—
Totals:      
Total volume hedged with floor price (Bbl) 1,727,300
 9,515,375
 730,000
Weighted-average floor price ($/Bbl) $55.82
 $47.42
 $50.00
Total volume hedged with ceiling price (Bbl) 1,462,800
 4,088,000
 —
Weighted-average ceiling price ($/Bbl) $57.22
 $60.00
 $—
Basis Swaps:      
Hedged volume (Bbl) —
 3,650,000
 —
Weighted-average price ($/Bbl) $—
 $(0.56) $—
NGL positions:      
Swaps - Ethane:      
Hedged volume (Bbl) 111,000
 —
 —
Weighted-average price ($/Bbl) $11.24
 $—
 $—
Swaps - Propane:      
Hedged volume (Bbl) 93,750
 —
 —
Weighted-average price ($/Bbl) $22.26
 $—
 $—
Natural gas positions:  
  
  
Puts:      
Hedged volume (MMBtu) 2,010,000
 8,220,000
 —
Weighted-average price ($/MMBtu) $2.50
 $2.50
 $—
Collars:  
  
  
Hedged volume (MMBtu) 4,793,200
 15,585,500
 —
Weighted-average floor price ($/MMBtu) $2.86
 $2.50
 $—
Weighted-average ceiling price ($/MMBtu) $3.54
 $3.35
 $—
Totals:      
Total volume hedged with floor price (MMBtu) 6,803,200
 23,805,500
 —
Weighted-average floor price ($/MMBtu) $2.75
 $2.50
 $—
Total volume hedged with ceiling price (MMBtu) 4,793,200
 15,585,500
 —
Weighted-average ceiling price ($/MMBtu) $3.54
 $3.35
 $—
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Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)


b. Balance sheet presentation
In accordance with the Company's standard practice, its derivatives are subject to counterparty netting under their governing agreements. The Company's oil, NGL and natural gas derivatives are presented on a net basis as "Derivatives" on the unaudited consolidated balance sheets. See Note 8.a for a summary of the fair value of derivatives on a gross basis.
By using derivatives to hedge exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk. For the Company, market risk is the exposure to changes in the market price of oil, NGL and natural gas, which are subject to fluctuations from a variety of factors, including changes in supply and demand. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, thereby creating credit risk. The Company's counterparties are participants in the Senior Secured Credit Facility, which is secured by the Company's oil, NGL and natural gas reserves; therefore, the Company is not required to post any collateral. The Company does not require collateral from its derivative counterparties. The Company minimizes the credit risk in derivatives by: (i) limiting its exposure to any single counterparty, (ii) entering into derivatives only with counterparties that meet the Company's minimum credit quality standard or have a guarantee from an affiliate that meets the Company's minimum credit quality standard and (iii) monitoring the creditworthiness of the Company's counterparties on an ongoing basis.
Note 8—Fair value measurements
The Company accounts for its oil, NGL and natural gas derivatives at fair value. The fair value of derivatives is determined utilizing pricing models for similar instruments. The models use a variety of techniques to arrive at fair value, including quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward curves generated from a compilation of data gathered from third parties.
The Company has categorized its assets and liabilities measured at fair value, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).
Assets and liabilities recorded at fair value on the unaudited consolidated balance sheets are categorized based on inputs to the valuation techniques as follows: 
Level 1—Assets and liabilities recorded at fair value for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access. Active markets are considered to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2—Assets and liabilities recorded at fair value for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the assets or liabilities. Substantially all of these inputs are observable in the marketplace throughout the full term of the price risk management instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace.
Level 3—Assets and liabilities recorded at fair value for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. Unobservable inputs are not corroborated by market data. These inputs reflect management's own assumptions about the assumptions a market participant would use in pricing the asset or liability.
When the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety. The Company conducts a review of fair value hierarchy classifications on an annual basis. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities. Transfers between fair value hierarchy levels are recognized and reported in the period in which the transfer occurred. No transfers between fair value hierarchy levels occurred during the nine months ended September 30, 2017 or 2016.
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Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)


a. Fair value measurement on a recurring basis
The following tables summarize the Company's fair value hierarchy by commodity on a gross basis and the net presentation on the unaudited consolidated balance sheets for derivative assets and liabilities measured at fair value on a recurring basis as of the periods presented:
(in thousands) Level 1 Level 2 Level 3 Total gross fair value Amounts offset Net fair value presented on the unaudited consolidated balance sheets
As of September 30, 2017:            
Assets            
Current:            
Oil derivatives $—
 $27,097
 $—
 $27,097
 $(8,732) $18,365
NGL derivatives —
 —
 —
 —
 —
 —
Natural gas derivatives —
 4,955
 —
 4,955
 (4,955) —
Oil deferred premiums —
 —
 —
 —
 (2,754) (2,754)
Natural gas deferred premiums —
 —
 —
 —
 —
 —
Noncurrent:            
Oil derivatives $—
 $12,471
 $—
 $12,471
 $(4,052) $8,419
NGL derivatives —
 —
 —
 —
 —
 —
Natural gas derivatives —
 1,277
 —
 1,277
 (256) 1,021
Oil deferred premiums —
 —
 —
 —
 (4,376) (4,376)
Natural gas deferred premiums —
 —
 —
 —
 (719) (719)
Liabilities            
Current:            
Oil derivatives $—
 $(1,556) $—
 $(1,556) $8,732
 $7,176
NGL derivatives —
 (1,509) —
 (1,509) —
 (1,509)
Natural gas derivatives —
 —
 —
 —
 4,955
 4,955
Oil deferred premiums —
 —
 (14,277) (14,277) 2,754
 (11,523)
Natural gas deferred premiums —
 —
 (3,269) (3,269) —
 (3,269)
Noncurrent:            
Oil derivatives $—
 $(121) $—
 $(121) $4,052
 $3,931
NGL derivatives —
 —
 —
 —
 —
 —
Natural gas derivatives —
 —
 —
 —
 256
 256
Oil deferred premiums —
 —
 (8,810) (8,810) 4,376
 (4,434)
Natural gas deferred premiums —
 —
 (834) (834) 719
 (115)
Net derivative position $—
 $42,614
 $(27,190) $15,424
 $—
 $15,424
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Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)


(in thousands) Level 1 Level 2 Level 3 Total gross fair value Amounts offset Net fair value presented on the unaudited consolidated balance sheets
As of December 31, 2016:            
Assets            
Current:            
Oil derivatives $—
 $22,527
 $—
 $22,527
 $—
 $22,527
NGL derivatives —
 —
 —
 —
 —
 —
Natural gas derivatives —
 270
 —
 270
 (270) —
Oil deferred premiums —
 —
 —
 —
 (1,580) (1,580)
Natural gas deferred premiums —
 —
 —
 —
 —
 —
Noncurrent:            
Oil derivatives $—
 $8,718
 $—
 $8,718
 $—
 $8,718
NGL derivatives —
 —
 —
 —
 —
 —
Natural gas derivatives —
 1,377
 —
 1,377
 (1,377) —
Oil deferred premiums —
 —
 —
 —
 —
 —
Natural gas deferred premiums —
 —
 —
 —
 —
 —
Liabilities            
Current:            
Oil derivatives $—
 $(9,789) $—
 $(9,789) $—
 $(9,789)
NGL derivatives —
 (2,803) —
 (2,803) —
 (2,803)
Natural gas derivatives —
 (3,639) —
 (3,639) 270
 (3,369)
Oil deferred premiums —
 —
 (3,569) (3,569) 1,580
 (1,989)
Natural gas deferred premiums —
 —
 (3,043) (3,043) —
 (3,043)
Noncurrent:            
Oil derivatives $—
 $(4,552) $—
 $(4,552) $—
 $(4,552)
NGL derivatives —
 —
 —
 —
 —
 —
Natural gas derivatives —
 (133) —
 (133) 1,377
 1,244
Oil deferred premiums —
 —
 —
 —
 —
 —
Natural gas deferred premiums —
 —
 (2,386) (2,386) —
 (2,386)
Net derivative position $—
 $11,976
 $(8,998) $2,978
 $—
 $2,978
These items are included as "Derivatives" on the unaudited consolidated balance sheets. Significant Level 2 assumptions associated with the calculation of discounted cash flows used in the mark-to-market analysis of derivatives include each derivative contract's corresponding commodity index price, appropriate risk-adjusted discount rates and other relevant data.
The Company's deferred premiums associated with its derivative contracts are categorized as Level 3, as the Company utilizes a net present value calculation to determine the valuation. They are considered to be measured on a recurring basis as the derivative contracts they derive from are measured on a recurring basis. As derivative contracts containing deferred premiums are entered into, the Company discounts the associated deferred premium to its net present value at the contract trade date, using the Senior Secured Credit Facility rate at the trade date (historical input rates range from 1.69% to 3.56%), and then records the change in net present value to interest expense over the period from trade until the final settlement date at the end of the contract. After this initial valuation, the net present value of each deferred premium is not adjusted; therefore, significant increases (decreases) in the Senior Secured Credit Facility rate would result in a significantly lower (higher) fair value measurement for each new contract entered into that contained a deferred premium; however, the valuation for the deferred premiums already recorded would remain unaffected. While the Company believes the sources utilized to arrive at the fair value estimates are reliable, different sources or methods could have yielded different fair value estimates; therefore, on a quarterly basis, the valuation is compared to counterparty valuations and a third-party valuation of the deferred premiums for reasonableness.
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Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)


The following table presents actual cash payments required for deferred premiums as of September 30, 2017 for the periods presented:
(in thousands) September 30, 2017
Remaining 2017 $1,441
2018 20,335
2019 5,774
2020 391
  Total $27,941
A summary of the changes in net assets classified as Level 3 measurements for the periods presented are as follows:
 
Three months ended September 30, Nine months ended September 30,
(in thousands)
2017 2016 2017 2016
Balance of Level 3 at beginning of period
$(12,554) $(12,662) $(8,998)
$(14,619)
Change in net present value of derivative deferred premiums
(88) (51) (199)
(184)
Total purchases and settlements:
     


Purchases
(15,996) —
 (22,994)
(6,072)
Settlements(1)

1,448
 2,709
 5,001

10,871
Balance of Level 3 at end of period
$(27,190) $(10,004) $(27,190)
$(10,004)

(1)The amount for the nine months ended September 30, 2016 includes $3.9 million that represents the present value of deferred premiums settled in the Company's hedge restructuring upon their early termination.
b. Fair value measurement on a nonrecurring basis
The Company accounts for the impairment of long-lived assets, if any, at fair value on a nonrecurring basis. For purposes of fair value measurement, it was determined that the impairment of long-lived assets is classified as Level 3, based on the use of internally developed cash flow models. No impairments of long-lived assets were recorded during the nine months ended September 30, 2017 or 2016.
The Company accounts for the impairment of inventory, if any, at lower of cost or NRV on a nonrecurring basis. For purposes of fair value measurement, it was determined that the impairment of inventory is classified as Level 2, based on the use of a replacement cost approach. See Note 2.i for discussion of the Company's inventory impairments recorded during the nine months ended September 30, 2016. No impairments of inventory were recorded during the nine months ended September 30, 2017.
The accounting policies for impairment of oil and natural gas properties are discussed in Note 2.g. Significant inputs included in the calculation of discounted cash flows used in the impairment analysis include the Company's estimate of operating and development costs, anticipated production of evaluated reserves and other relevant data. See Note 2.g for discussion of the Company's full cost ceiling impairment recorded during the nine months ended September 30, 2016. There was no full cost ceiling impairment recorded during the nine months ended September 30, 2017.
The Company accounts for acquisitions of evaluated and unevaluated oil and natural gas properties under the acquisition method of accounting. Accordingly, the Company conducts assessments of net assets acquired and recognizes amounts for identifiable assets acquired and liabilities assumed at the estimated acquisition date fair values, while transaction costs associated with the acquisitions are expensed as incurred.
The Company makes various assumptions in estimating the fair values of assets acquired and liabilities assumed. The most significant assumptions relate to the estimated fair value of evaluated and unevaluated oil and natural gas properties. The fair value of these properties is measured using a discounted cash flow model that converts future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) forecasted oil, NGL and natural gas reserve quantities; (ii) future commodity strip prices as of the closing dates adjusted for transportation and regional price differentials; (iii) forecasted ad valorem taxes, production taxes, income taxes, general and administrative expenses, operating expenses and development costs; and (iv) a peer group weighted-average cost of capital rate subject to additional project-specific risk factors. To compensate for the inherent risk of estimating the value of the unevaluated properties, the discounted future net revenues of
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Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)


proved undeveloped and probable reserves are reduced by additional reserve adjustment factors. These assumptions represent Level 3 inputs under the fair value hierarchy. See Note 3.b for additional discussion of the Company's acquisitions of evaluated and unevaluated oil and natural gas properties during the nine months ended September 30, 2016. No acquisitions were recorded during the nine months ended September 30, 2017.
Note 9—11—Net income (loss) per common share
Basic and diluted net income (loss) per common share isare computed by dividing net income (loss) by the weighted-average number of common shares outstanding for the period. Diluted net income (loss) per common share reflects the potential dilution of non-vested restricted stock awards, outstanding stock option awards, non-vested performance share awards and the non-vested restricted stock awards and outstanding stock optionoutperformance share award. See Note 8 for additional discussion of these awards. For the ninethree months ended September 30, 2016,March 31, 2021, all of these potentially dilutive itemsawards were anti-dilutive due to the Company's net loss and, therefore, were excluded from the calculation of diluted net loss per common share.
The effect of the Company's outstanding stock option awards, with the exception of the options granted in 2016, was excluded from the calculation of diluted net income per common share for the three and nine months ended September 30, 2017. The inclusiondilutive effects of these options would be anti-dilutive due to the following: (i)awards were calculated utilizing the treasury stock method the sum of the assumed proceeds exceeded the average stock prices during the respective periods for the outstanding stock option awards granted in 2015 and (ii) the exercise prices were greater than the average market prices during the respective periods for the outstanding stock option awards granted in 2012, 2013, 2014 and 2017.
The effect of the Company's outstanding stock options was excluded from the calculation of diluted net income per common share for the three months ended September 30, 2016. The inclusion of these options would be anti-dilutive due to the following: (i) utilizing the treasury stock method, the sum of the assumed proceeds exceeded the average stock price during the period for the restricted stock option awards granted in 2016 and (ii) the exercise prices for all other outstanding stock options were greater than the average market price during the period.March 31, 2020.
The following istable reflects the calculationcalculations of basic and diluted (i) weighted-average common shares outstanding and (ii) net income (loss) per common share for the periods presented:
  Three months ended September 30, Nine months ended September 30,
(in thousands, except for per share data) 2017 2016 2017 2016
Net income (loss) (numerator):      
  
Net income (loss)—basic and diluted $11,027
 $9,485
 $140,413
 $(242,318)
Weighted-average common shares outstanding (denominator):        
Basic(1)
 239,306

234,639
 239,017
 221,303
Non-vested performance share awards(2)
 4,801
 3,216
 4,702
 —
Non-vested restricted stock awards(3)
 650
 253
 845
 —
Outstanding stock option awards(3) 
 130
 —
 129
 —
Diluted 244,887

238,108
 244,693
 221,303
Net income (loss) per common share:        
Basic $0.05
 $0.04
 $0.59
 $(1.09)
Diluted $0.05
 $0.04
 $0.57
 $(1.09)
Three months ended March 31,
(in thousands, except for per share data)20212020
Net income (loss) (numerator)$(75,439)$74,646 
Weighted-average common shares outstanding (denominator)(1):
Basic11,918 11,618 
Diluted11,918 11,673 
Net income (loss) per common share(1):
Basic$(6.33)$6.43 
Diluted$(6.33)$6.39 

(1)For the three months ended March 31, 2020, shares and per share data have been retroactively adjusted to reflect the Company's 1-for-20 reverse stock split effective June 1, 2020, as described in Note 7.b.
21
(1)For the three and nine months ended September 30, 2016, weighted-average common shares outstanding used in the computation of basic and diluted net income (loss) per common share attributable to stockholders was computed taking into account equity offerings that occurred during the respective periods. See Note 2.o for additional discussion of the Company's equity offerings.
(2)The dilutive effect of the non-vested performance share awards was calculated utilizing the Company's total shareholder return ("TSR") from the beginning of each performance share awards' respective performance period to the end of the respective period presented in comparison to the TSR of the peers specified in each performance share award's respective agreement. See Note 5.c for additional discussion of the Company's performance share awards.
(3)The dilutive effects of the non-vested restricted stock awards and the outstanding stock option awards were calculated utilizing the treasury stock method. See Notes 5.a and 5.b for additional discussion of the Company's restricted stock awards and stock option awards, respectively.
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)


Note 10—Credit risk
The Company's oil, NGL and natural gas sales are made to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. The Company's joint operations accounts receivable are from a number of oil and natural gas companies, partnerships, individuals and others who own interests in the oil and natural gas properties operated by the Company. The Company's sales of purchased oil are generally made to one customer. Management believes that any credit risk imposed by a concentration in the oil and natural gas industry is offset by the creditworthiness of the Company's customer base and industry partners. The Company routinely assesses the recoverability of all material trade and other receivables to determine collectability.
The Company uses derivatives to hedge its exposure to oil, NGL and natural gas price volatility. These transactions expose the Company to potential credit risk from its counterparties. In accordance with the Company's standard practice, its derivatives are subject to counterparty netting under agreements governing such derivatives; therefore, the credit risk associated with its derivative counterparties is somewhat mitigated. See Notes 2.e, 7 and 8.a for additional information regarding the Company's derivatives.
Note 11—12—Commitments and contingencies
a.    Litigation
From time to time, the Company is involved insubject to various legal proceedings and/or may be subject to industry rulings that could bring rise to claimsarising in the ordinary course of business. In the case of a known contingency,business, including proceedings for which the Company accrues a liability whenmay not have insurance coverage. While many of these matters involve inherent uncertainty, as of the loss is probable and the amount is reasonably estimable. Except with regard to the specific litigation noted below,date hereof, the Company has concludeddoes not currently believe that the likelihood is remote that the ultimate resolution of any such pending litigation or pending claimslegal proceedings will be material or have a material adverse effect on the Company's business, financial position, results of operations or liquidity.
On May 3, 2017, Shell Trading (US) Company ("Shell") filed an Original Petition and Request for Disclosure in the District Court of Harris County, Texas, alleging that the crude oil purchase agreement entered into between Shell and Laredo effective October 1, 2016 does not accurately reflect the compensation to be paid to Shell under certain circumstances due to a drafting mistake. Shell seeks reformation of one clause of the crude oil purchase agreement on the grounds of alleged mutual mistake or, in the alternative, unilateral mistake, an award of the amounts Shell alleges it should have been or should be paid under the agreement, court costs and attorneys’ fees. b.    Drilling rig contract
The Company does not believe there was a drafting mistake made in the crude oil purchase agreement. The Company believes it has substantive defenses and intendsenters into drilling rig contracts to vigorously defend its position. The Company is unableensure availability of desired rigs to determine a probability of the outcome of this litigation at this time. As of September 30, 2017, the Company has estimated an amount of $8.7 million related to this litigation that is not recorded in the accompanying unaudited consolidated balance sheets. Under the current pricing election, which elections are made for six-month periods, this estimate of the unrecorded amount will increase through the life of the contract.facilitate drilling plans. The Company has accounted2 operating leases for the costs (and resulting increased crude oil price realization) as reflected in the terms of the crude oil purchase agreement.
b.    Drilling contracts
The Company has committed to several drilling contracts with a third party to facilitate the Company's drilling plans. Two of these contracts are for a term of multiple months, andboth of which contain an early termination clauseclauses that requiresrequire the Company to potentially pay a penaltypenalties to the third party should the Company cease drilling efforts. This penaltyThese penalties would negatively impact the Company's financial statements upon early contract termination. There were no0 penalties incurred for early contract termination for either of the ninethree months ended September 30, 2017March 31, 2021 or 2016.2020. As these drilling rig contracts are operating leases, the present value of the future commitment as of March 31, 2021 related to the drilling rig contract with an initial term greater than 12 months is included in current and noncurrent "Operating lease liabilities" on the unaudited consolidated balance sheet as of March 31, 2021. The future commitment of $3.0$1.7 million as of September 30, 2017March 31, 2021 related to the drilling rig contract with an initial term less than 12 months is not recorded inon the accompanying unaudited consolidated balance sheets. Management does not currently anticipateSee Note 5 in the early termination2020 Annual Report for additional discussion of this contract in 2017.

the Company's leases.
c.    Firm sale and transportation commitments
The Company has committed to deliver, for sale or transportation, fixed volumes of product under certain contractual arrangements that specify the delivery of a fixed and determinable quantity. If not fulfilled, the Company is subject to deficiency payments.firm transportation payments on excess pipeline capacity and other contractual penalties. These commitments are normal and customary for the Company's business. In certain instances, the Company has used spot market purchases to meet its commitments in certain locations or due to favorable pricing. Management anticipates continuing this practice inA portion of the future.Company's commitments are related to transportation commitments with a certain pipeline pertaining to the gathering of the Company's production from established acreage that extends into 2024. The Company incurred deficiencywas unable to satisfy a portion of this particular commitment with produced or purchased oil, therefore, the Company expensed firm transportation payments on excess capacity of $0.5 million and $1.1 million during the three and nine months ended September 30, 2017, respectively, and $1.6 million during the three and nine months ended September 30, 2016,March 31, 2021, which are reportedis recorded in "Transportation and marketing expenses" on the unaudited consolidated statementsstatement of operations inoperations. NaN firm transportation payments on excess pipeline capacity were incurred during the "Other operating
Table of Contents
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)


expenses" line item. Future commitmentsthree months ended March 31, 2020. The Company's estimated aggregate liability of $369.4firm transportation payments on excess capacity is $4.4 million as of September 30, 2017March 31, 2021, and is included in "Accounts payable and accrued liabilities" on the unaudited consolidated balance sheet. As of March 31, 2021, future firm sale and transportation commitments of $258.8 million are expected to be satisfied, and as such, are not recorded inas a liability on the accompanying unaudited consolidated balance sheets. For information regardingsheet.
d.    Sand purchase commitment
During the TA relatedyear ended December 31, 2020, the Company entered into an agreement to Medallion, see Note 2.h.take delivery of processed sand at a fixed price for one year, which is utilized in the Company's completions activities, from its sand mine that is operated by a third-party contractor. As of March 31, 2021, under the terms of this agreement, the Company is required to purchase a certain volume remaining under its commitment or it would incur a shortfall payment of $3.4 million at the end of the contract period.
d.e.    Federal and state regulations

Oil and natural gas exploration, production and related operations are subject to extensive federal and state laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry increases the cost of doing business and affects profitability. The Company believes that it is in compliance with currently applicable federal and state regulations related to oil and natural gas exploration and production, and that compliance with the current regulations will not have a material adverse impact on the financial position or results of operations of the Company. These rules and regulations are frequently amended or reinterpreted; therefore, the Company is unable to predict the future cost or impact of complying with these regulations.
Note 12—Related parties
a.    Medallion
The following table summarizes items included in the unaudited consolidated balance sheets related to Medallion as of the dates presented:
22
(in thousands) December 31, 2016
Accrued capital expenditures $586
Other current liabilities $118
The following table summarizes items included in the unaudited consolidated statements of operations related to Medallion for the periods presented:
  Three months ended September 30, Nine months ended September 30,
(in thousands) 2017 2016 2017 2016
Loss on disposal of assets, net $(70) $—
 $(70) $—
See Note 2.h for discussion of the TA between LMS and a wholly-owned subsidiary of Medallion and see Note 16.a for discussion of the Medallion Sale subsequent to September 30, 2017.
b.    Archrock Partners, L.P.
The Company has a compression arrangement with affiliates of Archrock Partners, L.P., formerly Exterran Partners L.P. ("Archrock"). One of Laredo's directors is on the board of directors of Archrock GP LLC, an affiliate of Archrock.
As of December 31, 2016, amounts included in accounts payable from Archrock in the unaudited consolidated balance sheets totaled $0.2 million. No such amounts were included as of September 30, 2017.
The following table summarizes the lease operating expenses related to Archrock included in the unaudited consolidated statements of operations for the periods presented:
  Three months ended September 30, Nine months ended September 30,
(in thousands) 2017 2016 2017 2016
Lease operating expenses $72
 $498
 $728
 $1,499
For the nine months ended September 30, 2016, amounts included in capital expenditures for midstream service assets from Archrock in the unaudited consolidated statements of cash flows totaled a de minimis amount. No such amounts were included for the nine month ends ended September 30, 2017.     
Note 13—Segments
The Company operates in two business segments: (i) exploration and production and (ii) midstream and marketing. The exploration and production segment is engaged in the acquisition, exploration and development of oil and natural gas properties. The midstream and marketing segment provides Laredo's exploration and production segment and third parties with products and services that need to be delivered by midstream infrastructure, including oil and liquids-rich natural gas gathering services as well as rig fuel, natural gas lift and water delivery and takeaway.
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)


f.    Environmental
The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, among other things, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed in the period incurred. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. Management believes 0 materially significant liabilities of this nature existed as of March 31, 2021 or December 31, 2020.
Note 13—Supplemental cash flow and non-cash information
The following table presents selected financialsupplemental cash flow and non-cash information for the periods presented, regardingpresented:
Three months ended March 31,
(in thousands)20212020
Supplemental cash flow information:
Cash paid for interest, net of $449 and $1,181 of capitalized interest, respectively$48,030 $23,697 
Supplemental non-cash investing information:
Change in accrued capital expenditures$(351)$16,272 
Capitalized share-settled equity-based compensation$670 $965 
Capitalized asset retirement cost$397 $886 
Note 14—Asset retirement obligations
See Note 2.k in the 2020 Annual Report for discussion of the Company's significant accounting policies for asset retirement obligations.
The following table reconciles the Company's asset retirement obligation liability associated with tangible long-lived assets for the periods presented:
Three months ended March 31,
(in thousands)20212020
Liability at beginning of period$68,326 $62,718 
Liabilities added due to acquisitions, drilling, midstream service asset construction and other397 886 
Accretion expense (1)
1,143 1,106 
Liabilities settled due to plugging and abandonment or removed due to sale(57)(497)
Liability at end of period$69,809 $64,213 

(1)Accretion expense is included in "Other operating segmentsexpenses" on a stand-alone basisthe unaudited consolidated statements of operations.
Note 15—Revenue recognition
Oil, NGL and natural gas sales and sales of purchased oil are generally recognized at the point in time that control of the product is transferred to the customer. Midstream service revenues are recognized over time as the customer benefits from these services when provided. A more detailed summary of the underlying contracts that give rise to the Company's revenues and methods of recognition can be found in Note 14 in the 2020 Annual Report.
Note 16—Income taxes
The Company is subject to federal and state income taxes and the consolidation and elimination entries necessary to arrive at the information forTexas franchise tax. As of March 31, 2021, the Company on a consolidated basis:had federal net operating loss carryforwards totaling $2.1 billion, and of this amount, $1.7 billion will begin to expire in 2026 and $397.6 million will not expire but may be limited in future periods, and state of Oklahoma net operating loss
23
(in thousands)
Exploration and production
Midstream and marketing
Eliminations
Consolidated company
Three months ended September 30, 2017:        
Revenues:        
Oil, NGL and natural gas sales $158,037
 $845
 $(1,324) $157,558
Midstream service revenues —
 16,892
 (14,446) 2,446
Sales of purchased oil —
 45,814
 —
 45,814
Total revenues 158,037
 63,551
 (15,770) 205,818
Costs and expenses:        
Lease operating expenses, including production and ad valorem taxes 32,417
 —
 (3,265) 29,152
Midstream service expenses —
 12,474
 (11,300) 1,174
Costs of purchased oil —
 47,385
 —
 47,385
General and administrative(1)
 22,962
 2,038
 —
 25,000
Depletion, depreciation and amortization(2)
 38,802
 2,410
 —
 41,212
Other operating expenses(3)
 1,386
 57
 —
 1,443
Operating income (loss) $62,470
 $(813) $(1,205) $60,452
Other financial information:        
Income from equity method investee $—
 $2,371
 $—
 $2,371
Interest expense(4)
 $22,184
 $1,513
 $—
 $23,697
Capital expenditures $149,867
 $5,563
 $—
 $155,430
Gross property and equipment(5)
 $6,149,485
 $443,462
 $(14,431) $6,578,516
Three months ended September 30, 2016:        
Revenues:        
Oil, NGL and natural gas sales $115,188
 $488

$(871) $114,805
Midstream service revenues —
 15,357

(12,869) 2,488
Sales of purchased oil —
 42,441

—
 42,441
Total revenues 115,188
 58,286
 (13,740) 159,734
Costs and expenses:        
Lease operating expenses, including production and ad valorem taxes 28,624
 —

(3,381) 25,243
Midstream service expenses —
 9,079

(8,040) 1,039
Costs of purchased oil —
 44,232

—
 44,232
General and administrative(1)
 23,883
 2,222

—
 26,105
Depletion, depreciation and amortization(2)
 32,883
 2,275

—
 35,158
Other operating expenses(3)
 2,414
 51

—
 2,465
Operating income $27,384
 $427
 $(2,319) $25,492
Other financial information:        
Income from equity method investee $—
 $265

$—
 $265
Interest expense(4)
 $21,631
 $1,446

$—
 $23,077
Capital expenditures $79,843
 $806

$—
 $80,649
Gross property and equipment(5)
 $5,682,251
 $384,091
 $(6,923) $6,059,419
Nine months ended September 30, 2017:        
Revenues:        
Oil, NGL and natural gas sales $439,533
 $2,486
 $(3,888) $438,131
Midstream service revenues —
 52,630
 (44,482) 8,148
Sales of purchased oil —
 135,546
 —
 135,546
Total revenues 439,533
 190,662
 (48,370) 581,825
Costs and expenses:        
Lease operating expenses, including production and ad valorem taxes 93,980
 —
 (10,479) 83,501
Midstream service expenses —
 34,686
 (31,700) 2,986
Costs of purchased oil —
 141,661
 —
 141,661
General and administrative(1)
 66,526
 6,079
 —
 72,605
Depletion, depreciation and amortization(2)
 106,282
 7,045
 —
 113,327
Other operating expenses(3)
 3,741
 165
 —
 3,906
Operating income $169,004
 $1,026
 $(6,191) $163,839
Other financial information:        
Income from equity method investee $—
 $7,910
 $—
 $7,910
TABLE CONTINUES ON NEXT PAGE        
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)

carryforwards totaling $34.5 million that will begin to expire in 2032. As of March 31, 2021, the Company believes it is more likely than not that a portion of the net operating loss carryforwards are not fully realizable. The Company continues to consider new evidence, both positive and negative, in determining whether, based on the weight of that evidence, a valuation allowance is needed. Such consideration includes projected future cash flows from its oil, NGL and natural gas reserves (including the timing of those cash flows), the reversal of deferred tax liabilities recorded as of March 31, 2021, the Company's ability to capitalize intangible drilling costs, rather than expensing these costs and future projections of Oklahoma sourced income. As of March 31, 2021, a total valuation allowance of $505.1 million has been recorded to offset the Company's federal and Oklahoma net deferred tax assets, resulting in a Texas net deferred tax asset of $2.2 million, which is included in "Other noncurrent assets, net" on the unaudited consolidated balance sheets.
Note 17—Related parties
Halliburton
The Chairman of the Company's board of directors is on the board of directors of Halliburton Company ("Halliburton"). Halliburton provides drilling and completions services to the Company.
The following table presents the capital expenditures for oil and natural gas properties paid to Halliburton included in the unaudited consolidated statements of cash flows for the periods presented:
 Three months ended March 31,
(in thousands)20212020
Capital expenditures for oil and natural gas properties$11,780 $27,225 
24

(in thousands)
Exploration and production
Midstream and marketing
Eliminations
Consolidated company
Interest expense(4)
 $65,250
 $4,340
 $—
 $69,590
Capital expenditures $384,769
 $11,680
 $—
 $396,449
Gross property and equipment(5)
 $6,149,485
 $443,462
 $(14,431) $6,578,516
Nine months ended September 30, 2016:        
Revenues:        
Oil, NGL and natural gas sales $290,856
 $488
 $(871) $290,473
Midstream service revenues —
 37,762
 (31,841) 5,921
Sales of purchased oil —
 116,670
 —
 116,670
Total revenues 290,856
 154,920
 (32,712) 413,064
Costs and expenses:        
Lease operating expenses, including production and ad valorem taxes 87,781
 —
 (8,378) 79,403
Midstream service expenses —
 22,160
 (19,334) 2,826
Costs of purchased oil —
 121,190
 —
 121,190
General and administrative(1)
 60,380
 5,678
 —
 66,058
Depletion, depreciation and amortization(2)
 104,144
 6,669
 —
 110,813
Impairment expense 162,027
 —
 —
 162,027
Other operating expenses(3)
 4,012
 157
 —
 4,169
Operating loss $(127,488) $(934) $(5,000) $(133,422)
Other financial information:        
Income from equity method investee $—
 $6,259
 $—
 $6,259
Interest expense(4)
 $65,984
 $4,310
 $—
 $70,294
Capital expenditures $277,717
 $4,231
 $—
 $281,948
Gross property and equipment(5)
 $5,682,251
 $384,091
 $(6,923) $6,059,419

(1)
General and administrative expenses were allocated to the three months ended September 30, 2017, June 30, 2017, March 31, 2017, September 30, 2016, June 30, 2016 and March 31, 2016 based on the number of employees in the respective segment as of the respective three-month period end dates. Certain components of general and administrative expenses, primarily payroll, deferred compensation and vehicle expenses, were not allocated but were actual expenses for each segment. Land and geology expenses were not allocated to the midstream and marketing segment.
(2)
Depletion, depreciation and amortization were actual expenses for each segment with the exception of the allocation of depreciation of other fixed assets, which was allocated to the three months ended September 30, 2017, June 30, 2017 and March 31, 2017 based on the number of employees in the respective segment as of the respective three-month period end dates. Depreciation of other fixed assets was allocated to the three and nine months ended September 30, 2016 based on the number of employees in the respective segment as of September 30, 2016. Certain components of depreciation and amortization of other fixed assets, primarily vehicles, were not allocated but were actual expenses for each segment.
(3)
Other operating expenses consist of accretion of asset retirement obligations and minimum volume commitments. These were actual expenses and were not allocated.
(4)
Interest expense for the three months ended September 30, 2017, June 30, 2017 and March 31, 2017 was allocated to the exploration and production segment based on gross property and equipment as of September 30, 2017, June 30, 2017 and March 31, 2017, respectively, and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of September 30, 2017, June 30, 2017 and March 31, 2017, respectively. Interest expense for the three and nine months ended September 30, 2016 was allocated to the exploration and production segment based on gross property and equipment as of September 30, 2016 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of September 30, 2016. Certain components of other fixed assets, primarily vehicles, were not allocated but were actual assets for each segment.
(5)Gross property and equipment for the midstream and marketing segment includes equity method investment of $276.4 million and $229.9 million as of September 30, 2017 and 2016, respectively. Other fixed assets were allocated based on the number of employees in the respective segment as of September 30, 2017 and 2016. Certain components of other fixed assets, primarily vehicles, were not allocated but were actual assets for each segment.
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)


Note 14—Subsidiary guarantors18—Subsequent events
The Guarantors have fully and unconditionally guaranteed the January 2022 Notes, the May 2022 Notes, the March 2023 Notes and thea.    Senior Secured Credit Facility subject to the Releases. In accordance with practices accepted by the SEC, Laredo has prepared condensed consolidating financial statements to quantify the balance sheets, results of operations and cash flows of such subsidiaries as subsidiary guarantors. The following unaudited condensed consolidating balance sheets as of September 30, 2017 and December 31, 2016, unaudited condensed consolidating statements of operations for the three and nine months ended September 30, 2017 and 2016 and unaudited condensed consolidating statements of cash flows for the nine months ended September 30, 2017 and 2016 present financial information for Laredo on a stand-alone basis (carrying any investment in subsidiaries under the equity method), financial information for the subsidiary guarantors on a stand-alone basis (carrying any investment in subsidiaries under the equity method), and the consolidation and elimination entries necessary to arrive at the information for the Company on a condensed consolidated basis. Deferred income taxes for LMS and for GCM are recorded on Laredo's balance sheets, statements of operations and statements of cash flows as they are disregarded entities for income tax purposes. Laredo and the Guarantors are not restricted from making intercompany distributions to each other. During the three and nine months ended September 30, 2016, certain assets were transferred from Laredo to LMS and from LMS to Laredo at historical cost.
Condensed consolidating balance sheet
September 30, 2017
(Unaudited)
(in thousands) Laredo
Subsidiary
Guarantors
Intercompany
eliminations
Consolidated
company
Accounts receivable, net $74,133
 $15,707
 $—
 $89,840
Other current assets 49,922
 2,703
 —
 52,625
Oil and natural gas properties, net 1,464,197
 9,244
 (14,431) 1,459,010
Midstream service assets, net —
 130,407
 —
 130,407
Other fixed assets, net 41,502
 400
 —
 41,902
Investment in subsidiaries and equity method investment 412,931
 276,435
 (412,931) 276,435
Other long-term assets 12,044
 4,063
 —
 16,107
Total assets $2,054,729
 $438,959
 $(427,362) $2,066,326
         
Accounts payable $20,975
 $1,820
 $—
 $22,795
Other current liabilities 179,550
 20,915
 —
 200,465
Long-term debt, net 1,440,968
 —
 —
 1,440,968
Other long-term liabilities 52,580
 3,293
 —
 55,873
Stockholders' equity 360,656
 412,931
 (427,362) 346,225
Total liabilities and stockholders' equity $2,054,729
 $438,959
 $(427,362) $2,066,326
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Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)


Condensed consolidating balance sheet
December 31, 2016
(Unaudited)
(in thousands) Laredo Subsidiary
Guarantors		 Intercompany
eliminations		 Consolidated
company
Accounts receivable, net $70,570
 $16,297
 $—
 $86,867
Other current assets 65,884
 2,026
 —
 67,910
Oil and natural gas properties, net 1,194,801
 9,293
 (8,240) 1,195,854
Midstream service assets, net —
 126,240
 —
 126,240
Other fixed assets, net 44,221
 552
 —
 44,773
Investment in subsidiaries and equity method investment 376,028
 243,953
 (376,028) 243,953
Other long-term assets 13,065
 3,684
 —
 16,749
Total assets $1,764,569
 $402,045
 $(384,268) $1,782,346
         
Accounts payable $14,427
 $627
 $—
 $15,054
Other current liabilities 150,531
 22,360
 —
 172,891
Long-term debt, net 1,353,909
 —
 —
 1,353,909
Other long-term liabilities 56,889
 3,030
 —
 59,919
Stockholders' equity 188,813
 376,028
 (384,268) 180,573
Total liabilities and stockholders' equity $1,764,569
 $402,045
 $(384,268) $1,782,346
Condensed consolidating statement of operations
For the three months ended September 30, 2017
(Unaudited)
(in thousands)
Laredo Subsidiary
Guarantors		 Intercompany
eliminations		 Consolidated
company
Total revenues
$157,902

$63,686

$(15,770)
$205,818
Total costs and expenses
97,686

62,245

(14,565)
145,366
Operating income
60,216

1,441

(1,205)
60,452
Interest expense
(23,697)
—

—

(23,697)
Other non-operating income (expense)
(24,287)
2,290

(3,731)
(25,728)
Income before income tax
12,232

3,731

(4,936)
11,027
Income tax
—

—

—

—
Net income
$12,232

$3,731

$(4,936)
$11,027
Condensed consolidating statement of operations
For the nine months ended September 30, 2017
(Unaudited)
(in thousands) Laredo Subsidiary
Guarantors		 Intercompany
eliminations		 Consolidated
company
Total revenues $439,269
 $190,926
 $(48,370) $581,825
Total costs and expenses 276,855
 183,310
 (42,179) 417,986
Operating income 162,414
 7,616
 (6,191) 163,839
Interest expense (69,590) —
 —
 (69,590)
Other non-operating income 53,780
 7,622
 (15,238) 46,164
Income before income tax 146,604
 15,238
 (21,429) 140,413
Income tax —
 —
 —
 —
Net income $146,604
 $15,238
 $(21,429) $140,413
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Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)


Condensed consolidating statement of operations
For the three months ended September 30, 2016
(Unaudited)
(in thousands) Laredo
Subsidiary
Guarantors
Intercompany
eliminations
Consolidated
company
Total revenues $115,091
 $58,383
 $(13,740) $159,734
Total costs and expenses 90,073
 55,590
 (11,421) 134,242
Operating income 25,018
 2,793
 (2,319) 25,492
Interest expense (23,077) —
 —
 (23,077)
Other non-operating income 9,863
 254
 (3,047) 7,070
Income before income tax 11,804
 3,047
 (5,366) 9,485
Income tax —
 —
 —
 —
Net income $11,804
 $3,047
 $(5,366) $9,485
Condensed consolidating statement of operations
For the nine months ended September 30, 2016
(Unaudited)
(in thousands) Laredo
Subsidiary
Guarantors
Intercompany
eliminations
Consolidated
company
Total revenues $290,724
 $155,052
 $(32,712) $413,064
Total costs and expenses 424,274
 149,924
 (27,712) 546,486
Operating income (loss) (133,550) 5,128
 (5,000) (133,422)
Interest expense (70,294) —
 —
 (70,294)
Other non-operating income (expense) (33,474) 6,237
 (11,365) (38,602)
Income (loss) before income tax (237,318) 11,365
 (16,365) (242,318)
Income tax —
 —
 —
 —
Net income (loss) $(237,318) $11,365
 $(16,365) $(242,318)
Condensed consolidating statement of cash flows
For the nine months ended September 30, 2017
(Unaudited)
(in thousands) Laredo Subsidiary
Guarantors		 Intercompany
eliminations		 Consolidated
company
Net cash provided by operating activities $273,309
 $13,980
 $(15,238) $272,051
Change in investment between affiliates (36,890) 21,652
 15,238
 —
Capital expenditures and other (321,261) (35,632) —
 (356,893)
Net cash provided by financing activities 72,988
 —
 —
 72,988
Net decrease in cash and cash equivalents (11,854) —
 —
 (11,854)
Cash and cash equivalents, beginning of period 32,671
 1
 —
 32,672
Cash and cash equivalents, end of period $20,817
 $1
 $—
 $20,818
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Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)


Condensed consolidating statement of cash flows
For the nine months ended September 30, 2016
(Unaudited)
(in thousands) Laredo Subsidiary
Guarantors		 Intercompany
eliminations		 Consolidated
company
Net cash provided by operating activities $244,213
 $12,606
 $(11,365) $245,454
Change in investment between affiliates (61,677) 50,312
 11,365
 —
Capital expenditures and other (392,977) (62,918) —
 (455,895)
Net cash provided by financing activities 209,647
 —
 —
 209,647
Net decrease in cash and cash equivalents (794) —
 —
 (794)
Cash and cash equivalents, beginning of period 31,153
 1
 —
 31,154
Cash and cash equivalents, end of period $30,359
 $1
 $—
 $30,360
Note 15—Recently issued or adopted accounting pronouncements
The Company considers the applicability and impact of all accounting standard updates ("ASU") issued by the Financial Accounting Standards Board ("FASB"). The discussion of the ASUs listed below were determined to be meaningful to the Company's consolidated financial statements and/or footnotes during the nine months ended September 30, 2017.
In May 2014, the FASB issued a comprehensive new revenue recognition standard that supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities—Oil and Gas—Revenue Recognition. The core principle of the new guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for transferring those goods or services. The new standard also requires significantly expanded disclosure regarding the qualitative and quantitative information of an entity's nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The standard creates a five-step model that requires companies to exercise judgment when considering the terms of a contract and all relevant facts and circumstances. The standard allows for several transition methods: (a) a full retrospective adoption in which the standard is applied to all of the periods presented, or (b) a modified retrospective adoption in which the standard is applied only to the most current period presented in the financial statements, including additional disclosures of the standard's application impact to individual financial statement line items. In March, April, May and December 2016,the FASB issued new guidance in Topic 606, Revenue from Contracts with Customers, to address the following potential implementation issues of the new revenue standard: (a) to clarify the implementation guidance on principal versus agent considerations, (b) to clarify the identification of performance obligations and the licensing implementation guidance and (c) to address certain issues in the guidance on assessing collectability, presentation of sales taxes, noncash consideration, and completed contracts and contract modifications at transition. This standard is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company follows the sales method of accounting for oil, NGL and natural gas production, which is generally consistent with the revenue recognition provision of the new standard. In regards to the exploration and production segment of its business, other than new disclosures, the Company does not anticipate the standard to have a material impact on its consolidated financial statements upon adoption based on its evaluation process. The evaluation process included (i) review of revenue contracts and transactions in both of the exploration and production and midstream and marketing segments and (ii) assessing the impact this guidance will have on our processes and internal controls. However, in light of the Medallion Sale, which occurred in the fourth quarter of 2017, the Company is currently evaluating the accounting impact and adoption method implications the adoption of this standard on the effective date of January 1, 2018 will have on the midstream and marketing segment of its business.
In February 2016, the FASB issued new guidance in Topic 842, Leases. The core principle of the new guidance is that a lessee should recognize the assets and liabilities that arise from leases in the statement of financial position. A lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. When measuring assets and liabilities arising from a lease, a lessee (and a lessor) should include payments to be made in optional periods only if the lessee is reasonably certain to exercise an option to extend the lease or not to exercise an option to terminate the lease. Similarly, optional payments to purchase the underlying asset should be included in the measurement of lease assets and lease liabilities only if the lessee is reasonably certain to exercise that purchase option. Reasonably certain is a high threshold that is consistent with and intended to be applied
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Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)


in the same way as the reasonably assured threshold in the previous lease guidance. In addition, also consistent with the previous lease guidance, a lessee (and a lessor) should exclude most variable lease payments in measuring lease assets and lease liabilities, other than those that depend on an index or a rate or are in substance fixed payments. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. If a lessee makes this election, it should recognize lease expense for such leases generally on a straight-line basis over the lease term. The recognition, measurement and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from previous GAAP. There continues to be a differentiation between finance leases and operating leases. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. These practical expedients relate to the identification and classification of leases that commenced before the effective date, initial direct costs for leases that commenced before the effective date and the ability to use hindsight in evaluating lessee options to extend or terminate a lease or to purchase the underlying asset. An entity that elects to apply the practical expedients will, in effect, continue to account for leases that commence before the effective date in accordance with previous GAAP unless the lease is modified, except that lessees are required to recognize a right-of-use asset and a lease liability for all operating leases at each reporting date based on the present value of the remaining minimum rental payments that were tracked and disclosed under previous GAAP. The amendments in this ASU are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application of the amendments in this ASU is permitted. The Company is in the process of evaluating the potential impact of adopting this guidance, and the primary effect will be to record assets and obligations for contracts currently recognized as operating leases with a term greater than 12 months and evaluate operating leases with a term less than or equal to 12 months for election. The Company does not intend to adopt the standard early. 
In January 2017, the FASB issued new guidance in Topic 805, Business Combinations, to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. Under the current implementation guidance in Topic 805, there are three elements of a business—inputs, processes and outputs. While an integrated set of assets and activities (collectively referred to as a “set”) that is a business usually has outputs, outputs are not required to be present. In addition, all the inputs and processes that a seller uses in operating a set are not required if market participants can acquire the set and continue to produce outputs, for example, by integrating the acquired set with their own inputs and processes. The amendments in this ASU provide a screen to determine when a set is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. This screen reduces the number of transactions that need to be further evaluated. If the screen is not met, the amendments in this ASU (i) require that to be considered a business, a set must include, at a minimum, an input and a substantive process that together significantly contribute to the ability to create an output and (ii) remove the evaluation of whether a market participant could replace missing elements. The amendments provide a framework to assist entities in evaluating whether both an input and a substantive process are present. The framework includes two sets of criteria to consider that depend on whether a set has outputs. Although outputs are not required for a set to be a business, outputs generally are a key element of a business; therefore, the FASB has developed more stringent criteria for sets without outputs. Lastly, the amendments in this ASU narrow the definition of the term output so that the term is consistent with how outputs are described in Topic 606. The amendments in this ASU are effective for annual periods beginning after December 15, 2017, including interim periods within those periods. The amendments in this ASU should be applied prospectively on or after the effective date. Early application of the amendments in this ASU is permitted. The Company is currently evaluating the impact this standard will have on its consolidated financial statements upon adoption.
Note 16—Subsequent events
a.    Medallion sale and capital call
On October 30, 2017, LMS, together with Medallion Midstream Holdings, LLC ("MMH"), which is ownedApril 6, 2021 and controlled by an affiliate of The Energy & Minerals Group ("EMG"), completed the previously announced Medallion Sale of 100% of the ownership interests in Medallion to an affiliate of Global Infrastructure Partners ("GIP"), for cash consideration of $1.825 billion, subject to customary post-closing adjustments. LMS' net cash proceeds for its 49% ownership interest in Medallion are $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. 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.

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Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)


On October 20, 2017, the Company made a capital contribution to Medallion of $7.2 million to fund continued expansion activities on existing portions of Medallion's pipeline infrastructure in order to gather additional third-party production.
See Note 2.h for additional discussion regarding Medallion, and see Note 12.a for discussion of items included in the Company's unaudited consolidated financial statements related to Medallion.
b.    Senior Secured Credit Facility
On October 24, 2017, the Company entered into the First Amendment (the "First Amendment") to the Senior Secured Credit Facility. The First Amendment, among other things, clarifies the repayment of senior notes negative covenant to permit the Company to redeem senior notes with an amount not exceeding the net cash proceeds from the sale or disposition of properties not constituting Borrowing Base Properties (as defined in the Senior Secured Credit Facility) and made within 365 days of the consummation of such sale or disposition, which would include the proceeds from the Medallion Sale.
In addition, on October 20, 2017, pursuant to a regular semi-annual redetermination, the lenders reaffirmed the borrowing base of $1.0 billion under the Senior Secured Credit Facility. The Company's aggregate elected commitment of $1.0 billion remained unchanged.
On October 5, 2017, October 11, 2017 and October 19, 2017,April 26, 2021, the Company borrowed an additional $20.0 million and made a $10.0 million $15.0 million and $10.0 million,payment, respectively, on the Senior Secured Credit Facility. On October 30, 2017,As a result, the Company repaid borrowings outstanding on the Senior Secured Credit Facility in the amount of $190.0 million with a portion of the proceeds from the Medallion Sale. There was no outstanding balance under the Senior Secured Credit Facility was $230.0 million as of October 31, 2017.May 3, 2021. See Note 6.c for additional discussion of the Company's Senior Secured Credit Facility.
c.    May 2022 Notes call for redemptionb.    Commodity derivatives
On October 30, 2017,The following table presents the commodity derivatives that were entered into by the Company issued a press release announcing that it called for redemption all $500.0 million aggregate principal amountsubsequent to March 31, 2021:
Aggregate volumes (Bbl)Weighted-average price ($/Bbl)Contract period
Brent ICE - Swaps365,000 $61.55 January 2022 - December 2022

The following table summarizes the resulting open oil derivative position as of its May 2022 Notes. The redemption dateMarch 31, 2021, updated for the above derivative transactions through May 2022 Notes is November 29, 2017, and holders will receive a redemption price of 103.688% of3, 2021, for the principal amount ofsettlement periods presented:
 Remaining Year 2021Year 2022
Oil: 
Brent ICE - Swaps:
Volume (Bbl)5,651,250 4,124,500 
Weighted-average price ($/Bbl)$51.29 $48.34 
Brent ICE - Collars: 
Volume (Bbl)440,000 821,250 
Weighted-average floor price ($/Bbl)$45.00 $53.67 
Weighted-average ceiling price ($/Bbl)$59.50 $62.40 
Total Brent ICE:
Total volume (Bbl)6,091,250 4,945,750 
Weighted-average floor price ($/Bbl)$50.83 $49.22 
Weighted-average ceiling price ($/Bbl)$51.88 $50.67 
See Note 9 for additional discussion regarding the May 2022 Notes, plus accrued and unpaid interest from November 1, 2017 through November 28, 2017.
Note 17—Supplementary information
Costs incurred in oil and natural gas property acquisition, exploration and development activities
Costs incurred in the acquisition, exploration and development of oil, NGL and natural gas assets are presented below:Company's derivatives. There has been no other derivative activity subsequent to March 31, 2021.
  Three months ended September 30, Nine months ended September 30,
(in thousands) 2017 2016 2017 2016
Property acquisition costs:  
  
  
 —
Evaluated(1)
 $—
 $5,905
 $—
 $5,905
Unevaluated —

110,800
 —
 110,800
Exploration costs 7,136

6,718
 28,337
 33,750
Development costs(2)
 160,359

72,411
 397,255
 225,103
Total costs incurred $167,495

$195,834
 $425,592
 $375,558
25

(1)
Evaluated property acquisition costs include $1.1 million in asset retirement obligations for the three and nine months ended September 30, 2016.
(2)Development costs include $0.4 million and $0.3 million in asset retirement obligations for the three months ended September 30, 2017 and 2016, respectively, and $0.6 million and $0.5 million for the nine months ended September 30, 2017 and 2016, respectively.



Item 2.    Management's Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations is for the three months ended March 31, 2021 and 2020, and should be read in conjunction with our unaudited consolidated financial statements and condensed notes thereto included elsewhere in this Quarterly Report as well as our audited consolidated financial statements and notes thereto included in our 20162020 Annual Report. The following discussion contains "forward-looking statements""forward-looking statements" that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results and the differences can be material. Please see "Cautionary"Cautionary Statement Regarding Forward-Looking Statements.Statements" and "Part II, Item 1A. Risk Factors." Except for purposes of the unaudited consolidated financial statements and condensed notes thereto included elsewhere in this Quarterly Report, references in this Quarterly Report to "Laredo,"Laredo, "we," "us,"we,""us,""our" "our" or similar terms refer to Laredo, LMS and GCM collectively, unless the context otherwise indicates or requires. 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 Quarterly Report are rounded and therefore approximate.
Executive overview
We are an independent energy company 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 inof West Texas. The oil and liquids-rich Permian Basin is characterized by multiple target horizons, extensive production histories, long-lived reserves, high drilling success rates and high initial production rates. Since our inception, we have grown primarily through our drilling program, coupled with select strategic acquisitions and joint ventures. As of March 31, 2021, we had assembled 133,352 net acres in the Permian Basin.
Our financial and operating performance included the following for the three months ended September 30, 2017 includedperiods presented and the following:corresponding changes for such periods:
Three months ended March 31,2021 compared to 2020
(in thousands)20212020Change (#)Change (%)
Oil sales volumes (MBbl)2,183 2,655 (472)(18)%
Oil equivalents sales volumes (MBOE)7,109 7,874 (765)(10)%
Oil, NGL and natural gas sales(1)
$202,457 $135,885 $66,572 49 %
Net income (loss)$(75,439)$74,646 $(150,085)(201)%
Free Cash Flow (a non-GAAP financial measure)(2)
$21,760 $(57,523)$79,283 138 %
Adjusted EBITDA (a non-GAAP financial measure)(2)
$93,323 $116,848 $(23,525)(20)%

Oil,(1)Our oil, NGL and natural gas sales increased as a result of $157.6 million, compared to $114.8 milliona 65% increase in average sales price per BOE and were partially offset by a 10% decrease in total volumes sold.
(2)See pages 39-40 for the three months ended September 30, 2016;
Average daily sales volumesdiscussions and calculations of 60,011 BOE/D, compared to 51,276 BOE/D for the three months ended September 30, 2016;
Net income of $11.0 million, compared to a net income of $9.5 million, for the three months ended September 30, 2016; and
Adjusted EBITDA (athese non-GAAP financial measure)measures.
Recent developments
ATM Program
On February 23, 2021, we entered into an equity distribution agreement with Wells Fargo Securities, LLC acting as sales agent and/or principal, pursuant to which we may offer and sell, from time to time through the sales agent, shares of $130.9our common stock having an aggregate gross sales price of up to $75.0 million comparedthrough the ATM Program.
As of March 31, 2021, we have sold 723,579 shares of our common stock pursuant to $118.0the ATM Program for net proceeds of approximately $26.9 million, after underwriting commissions and other related expenses. Proceeds from the share sale were utilized to reduce borrowings on the Senior Secured Credit Facility. The timing of any additional sales will depend on a variety of factors to be determined by us. See Note 7.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of the three months ended September 30, 2016. See page 49ATM Program.

26
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Weather
During February 2021, severe winter weather affected our operations resulting in downtime and delays that impacted total and oil production for a discussionfirst-quarter 2021 by an estimated 5,700 BOE per day and reconciliation1,700 barrels of Adjusted EBITDA.oil per day, respectively. Production impacts were less than originally anticipated and operations returned to pre-storm levels sooner than anticipated.
Our financial and operating performanceCOVID-19
COVID-19 continues to affect the demand for the nine months ended September 30, 2017 included the following:
Oil, NGLoil and natural gas salesand we are not able to predict the duration or ultimate impact that it will have on our business, financial condition and results of $438.1 million, comparedoperations. We continue to $290.5 millionclosely monitor local infection rates and to conform to guidelines and best practices encouraged by the Centers for Disease Control and Prevention, the nine months ended September 30, 2016;
Average daily sales volumes of 57,044 BOE/D, comparedWorld Health Organization and other governmental and regulatory authorities to 48,392 BOE/D for the nine months ended September 30, 2016;
Net income of $140.4 million, comparedtransition to appropriate return-to-work policies while minimizing interruptions to our operations. To date, these measures have not had a net loss of $242.3 million, including a non-cash full cost ceiling impairment of $161.1 million, for the nine months ended September 30, 2016; and
Adjusted EBITDA (a non-GAAP financial measure) of $352.6 million, compared to $326.3 million for the nine months ended September 30, 2016. See page 49 for a discussion and reconciliation of Adjusted EBITDA.
Recent developments
Medallion salematerial effect on our workforce productivity.
On October 30, 2017, LMS, together with MMH, which is owned and controlled by an affiliate of EMG, completedMarch 27, 2020, the previously announced Medallion Sale to an affiliate of GIP, for cash consideration of $1.825 billion, subject to customary post-closing adjustments. LMS' net cash proceeds for its 49% ownership interestCARES Act was enacted in Medallion are $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. The Medallion Sale closed pursuantresponse to the membership interest purchaseCOVID-19 pandemic. It included provisions intended to provide relief to individuals 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 whenbusinesses in the form of loans and whether any such additional consideration will be paid.

May 2022 Notes call for redemption
On October 30, 2017, we issued a press release announcing thatgrants, and tax changes, among other provisions. We did not seek relief in the form of loans or grants from the CARES Act; however, we have calledbenefited from the provision where the AMT credit carryforwards do not expire and are fully refundable.
Volatility in Commodity Prices
In the spring of 2020, action by members of OPEC+ attempting to stabilize the oil market and a slow reaction by U.S. and global producers to reduce oil production at a rate sufficient to match the sharp economic slowdown caused by COVID-19, resulted in an oversupply of oil that caused WTI oil prices to fall to -$37 per barrel on April 20, 2020. Following the April 20th low, WTI oil prices rebounded in the second half of 2020 and have averaged $58 per barrel during first-quarter 2021 and averaged $59 per barrel through April 2021.
We maintain an active, multi-year commodity derivatives strategy to minimize commodity price volatility and support cash flows needed for redemption the outstanding $500.0operations. For 2021, we currently have oil derivatives in place for 6.1 million aggregate principal amount of our May 2022 Notes. The redemption date for the May 2022 Notes is November 29, 2017, and holders will receivebarrels at a redemptionweighted-average floor price of 103.688%$50.83 Brent per barrel. For 2022, we currently have oil derivatives in place for 4.9 million barrels at a weighted-average floor price of the principal amount of the May 2022 Notes, plus accrued and unpaid interest from November 1, 2017 through November 28, 2017.$49.22 Brent per barrel.
Pricing and reserves
Our results of operations are heavily influenced by oil, NGL and natural gas prices. Oil, NGL and natural gas price fluctuations are caused by changes in global and regional supply and demand, market uncertainty, economic conditions and a variety of additional factors. Historically, commodity prices have experienced significant fluctuations, and additional changesfluctuations; however, the volatility in commodity prices has substantially increased as a result of world developments in 2020. The duration of such developments may affect the economic viability of, and our ability to fund, our drilling projects, as well as the economic valuation and economic recovery of oil, NGL and natural gas reserves.
The Realized Prices utilized to value our reserves as of September 30, 2017 and September 30, 2016 were $44.59 per Bbl for oil, $16.55 per Bbl for NGL and $2.16 per Mcf for natural gas, and $36.39 per Bbl for oil, $10.91 per Bbl for NGL and $1.65 per Mcf for natural gas, respectively. The Realized Prices used to estimate proved reserves as of all period end dates do not include derivative transactions. The unamortized cost of our evaluated oil and natural gas properties did not exceed the full cost ceiling amount as of September 30, 2017, June 30, 2017, March 31, 2017, September 30, 2016 or June 30, 2016. See Note 2.g to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for our discussion of our 2016 first-quarter full cost ceiling impairment.
We have entered into a number of commodity derivative contracts that have enabled us to offset a portion of the changes in our cash flow caused by fluctuations in price fluctuationsand basis differentials for our sales of oil, NGL and natural gas, as discussed in "Item 3. Quantitative and Qualitative Disclosures About Market Risk." See Notes 9, 10.a and 18.b to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our commodity derivatives.
Core areasOur reserves are reported in three streams: oil, NGL and natural gas. The Realized Prices utilized to value our proved reserves as of March 31, 2021 and March 31, 2020, are as follows:
March 31, 2021March 31, 2020
Realized Prices:
   Oil ($/Bbl)$38.28 $52.47 
   NGL ($/Bbl)$9.92 $10.47 
   Natural gas ($/Mcf)$1.20 $0.28 
The Realized Prices used to estimate proved reserves do not include derivative transactions. The unamortized cost of evaluated oil and natural gas properties being depleted exceeded the full cost ceiling for each of the quarterly periods in 2020 and, as such, we recorded non-cash full cost ceiling impairments totaling $889.5 million during the year ended December 31,
27
Table of Contents
2020. No such full cost ceiling impairment was recorded as of March 31, 2021. Additionally, given current commodity prices, we do not anticipate recording a full cost ceiling impairment in the second quarter of 2021. See Note 5 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for discussion of the full cost method of accounting and our Realized Prices.
Horizontal drilling of unconventional wells using enhanced completions techniques, including, but not limited to, hydraulic fracturing, is a continually evolving process and, as such, forecasting the long-term production of such wells is inherently uncertain and subject to varying interpretations. As we receive and process geological and production data from these wells over time, we analyze such data to confirm whether previous assumptions regarding original forecasted production, inventory and reserves continue to appear accurate or require modification. While all production forecasts have elements of uncertainty over the life of the related wells, we have observed over multiple years that oil decline rates are impacted by the vertical and horizontal spacing of wells. In 2020, all wells in our established acreage and Western Glasscock were drilled and completed at the wider spacing to mitigate this effect. Wells in Howard County were and continue to be completed at various horizontal spacing patterns as we test the optimum spacing in that area. In order to mitigate potential negative revisions in future years, we have taken a conservative approach in regards to oil rate forecasts on future wells in Howard County.
Initial production results, production decline rates, well density, completions design and operating method are examples of the numerous uncertainties and variables inherent in the estimation of proved reserves in future periods. The quantity of proved reserves is one of the many variables inherent in the calculation of depletion.
Results of operations
The oil and liquids-rich Permian Basin is characterized by multiple target horizons, extensive production histories, long-lived reserves, high drilling success rates and high initial production rates. As of September 30, 2017, we had assembled 125,466 net acres in the Permian Basin.Revenues
Sources of our revenue
Our revenues are derived from the sale of produced oil, NGL and natural gas, within the continental United States, the sale of purchased oil and providing midstream services to third parties. Our revenuesparties, all within the continental U.S. and do not include the effects of derivatives. For the three months ended September 30, 2017,See Note 15 to our revenues were comprised of: 54% salesunaudited consolidated financial statements included elsewhere in this Quarterly Report and Note 14 in our 2020 Annual Report for additional information regarding our revenue recognition policies.

The following table presents our sources of produced oil, 13% sales of produced NGL, 10% sales of produced natural gas, 22% sales of purchased oil and 1% midstream services. For the nine months ended September 30, 2017, our revenues were comprised of: 54% sales of produced oil, 12% sales of produced NGL, 10% sales of produced natural gas, 23% sales of purchased oil and 1% midstream services. Our oil, NGL and natural gas revenues may vary significantly from period to periodrevenue as a resultpercentage of changes in volumes of production and/or changes in commodity prices. Our sales of purchased oil revenue may vary due to changes in oil prices. Our midstream servicetotal revenues may vary due to oil throughput feesfor the periods presented and the levelcorresponding changes for such periods:
Three months ended March 31,2021 compared to 2020
20212020Change (#)Change (%)
Oil sales51 %59 %(8)%(14)%
NGL sales17 %6 %11 %183 %
Natural gas sales13 %2 %11 %550 %
Midstream service revenues1 %1 %— %— %
Sales of purchased oil18 %32 %(14)%(44)%
Total100 %100 %

28
Table of services provided to third parties for (i) gathered natural gas, (ii) gas lift fees and (iii) water services.Contents

Results of operations consolidated
For the three and nine months ended September 30, 2017 as compared to the three and nine months ended September 30, 2016
Oil, NGL and natural gas sales volumes, revenues and prices
The following table sets forthpresents information regarding our oil, NGL and natural gas sales volumes, sales revenues and average sales prices for the periods presented:presented and the corresponding changes for such periods:
  Three months ended September 30, Nine months ended September 30,
  2017 2016 2017 2016
Sales volumes:  

 
  
  
Oil (MBbl) 2,425

2,150
 7,027
 6,168
NGL (MBbl) 1,491
 1,272
 4,187
 3,491
Natural gas (MMcf) 9,630

7,766
 26,154
 21,600
Oil equivalents (MBOE)(1)(2)
 5,521

4,718
 15,573
 13,260
Average daily sales volumes (BOE/D)(2)
 60,011

51,276
 57,044
 48,392
% Oil 44%
46% 45% 47%
Oil, NGL and natural gas sales (in thousands): 


   
  
Oil $110,194

$84,083
 $313,875
 $218,478
NGL 27,700
 14,678
 68,329
 37,850
Natural gas 19,664

16,044
 55,927
 34,145
Total oil, NGL and natural gas sales $157,558

$114,805
 $438,131
 $290,473
Average sales prices: 


   
  
Oil, realized ($/Bbl)(3)
 $45.44

$39.10
 $44.67
 $35.42
NGL, realized ($/Bbl)(3)
 $18.58

$11.54
 $16.32
 $10.84
Natural gas, realized ($/Mcf)(3)
 $2.04

$2.07
 $2.14
 $1.58
Average price, realized ($/BOE)(3)
 $28.54

$24.34
 $28.13
 $21.91
Oil, hedged ($/Bbl)(4)
 $50.72

$57.57
 $49.08
 $57.76
NGL, hedged ($/Bbl)(4)
 $17.98

$11.54
 $15.90
 $10.84
Natural gas, hedged ($/Mcf)(4)
 $2.10

$2.31
 $2.17
 $2.18
Average price, hedged ($/BOE)(4)
 $30.80

$33.15
 $30.07
 $33.27
 Three months ended March 31,2021 compared to 2020
20212020Change (#)Change (%)
Sales volumes:  
Oil (MBbl)2,183 2,655 (472)(18)%
NGL (MBbl)2,321 2,467 (146)(6)%
Natural gas (MMcf)15,630 16,512 (882)(5)%
Oil equivalents (MBOE)(1)(2)
7,109 7,874 (765)(10)%
Average daily oil equivalent sales volumes (BOE/D)(2)
78,989 86,532 (7,543)(9)%
Average daily oil sales volumes (Bbl/D)(2)
24,261 29,178 (4,917)(17)%
Sales revenues (in thousands):  
Oil$127,701 $119,978 $7,723 6 %
NGL41,678 11,558 30,120 261 %
Natural gas33,078 4,349 28,729 661 %
Total oil, NGL and natural gas sales revenues$202,457 $135,885 $66,572 49 %
Average sales prices(2):
  
Oil ($/Bbl)(3)
$58.48 $45.19 $13.29 29 %
NGL ($/Bbl)(3)
$17.96 $4.68 $13.28 284 %
Natural gas ($/Mcf)(3)
$2.12 $0.26 $1.86 715 %
Average sales price ($/BOE)(3)
$28.48 $17.26 $11.22 65 %
Oil, with commodity derivatives ($/Bbl)(4)
$45.03 $56.59 $(11.56)(20)%
NGL, with commodity derivatives ($/Bbl)(4)
$11.25 $6.85 $4.40 64 %
Natural gas, with commodity derivatives ($/Mcf)(4)
$1.66 $0.94 $0.72 77 %
Average sales price, with commodity derivatives ($/BOE)(4)
$21.15 $23.21 $(2.06)(9)%

(1)BOE is calculated using a conversion rate of six Mcf per one Bbl.
(1)
BOE is calculated using a conversion rate of six Mcf per one Bbl.
(2)The volumes presented are based on actual results and are not calculated using the rounded numbers presented in the table above.
(3)Realized oil, NGL and natural gas prices are the actual prices realized at the wellhead adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. The prices presented are based on actual results and are not calculated using the rounded numbers presented in the table above.
(4)Hedged prices reflect the after-effect of our hedging
(2)The numbers presented in the three months ended March 31, 2021 and 2020 columns are based on actual amounts and are not calculated using the rounded numbers presented in the table above or the table below.
(3)Price reflects the average of actual sales prices received when control passes to the purchaser/customer adjusted for quality, certain 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 current period 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 instruments that settled in the period. The prices presented are based on actual results and are not calculated using the rounded numbers presented in the table above and below.

The following table presents cash settlements received (paid) for matured derivatives and premiums incurred previously or upon settlement that are attributable to instrumentscommodity derivatives that settled during the respective periods.

29
The following table presents net settlements (paid) received for matured commodity derivatives and net premiums paid previously or upon settlement attributable to commodity derivatives that matured during the periods utilized in our calculation of the hedgedaverage sales prices, with commodity derivatives, for the periods presented above:        
  Three months ended September 30, Nine months ended September 30,
(in thousands) 2017 2016 2017 2016
Cash settlements received (paid) for matured derivatives: 




    
Oil $13,182

$42,442
 $33,399
 $144,750
NGL (897) —
 (1,761) —
Natural gas 1,350

1,865
 3,153
 12,876
Total $13,635

$44,307
 $34,791
 $157,626
Premiums paid attributable to contracts that matured during the respective period: 




    
Oil $(362)
$(2,709) $(2,383) $(6,972)
Natural gas (769)
—
 (2,301) —
Total $(1,131)
$(2,709) $(4,684) $(6,972)
and the corresponding changes for such periods:     
Three months ended March 31,2021 compared to 2020
(in thousands)20212020Change ($)Change (%)
Net settlements (paid) received for matured commodity derivatives:
Oil$(18,371)$31,147 $(49,518)(159)%
NGL(15,576)5,337 (20,913)(392)%
Natural gas(7,173)11,239 (18,412)(164)%
Total$(41,120)$47,723 $(88,843)(186)%
Net premiums paid previously or upon settlement attributable to commodity derivatives that matured during the respective period:
Oil$(11,005)$(877)$(10,128)(1,155)%
Changes in average realized sales prices and sales volumes caused the following changes to our oil, NGL and natural gas revenues between the three months ended September 30, 2017March 31, 2021 and 2016:
2020:
(in thousands) Oil NGL Natural gas 
Total net
effect of change
2016 Revenues $84,083
 $14,678
 $16,044

$114,805
Effect of changes in average realized sales prices 15,378
 10,502
 (230) 25,650
Effect of changes in sales volumes 10,733
 2,520
 3,850
 17,103
2017 Revenues $110,194
 $27,700
 $19,664
 $157,558
(in thousands)OilNGLNatural gasTotal 
First-quarter 2020 revenues$119,978 $11,558 $4,349 

$135,885 
Effect of changes in average sales prices29,036 30,807 28,961 88,804 
Effect of changes in sales volumes(21,313)(687)(232)(22,232)
First-quarter 2021 revenues$127,701 $41,678 $33,078 $202,457 
Change ($)$7,723 $30,120 $28,729 $66,572 
Change (%)6 %261 %661 %49 %
ChangesIn the three months ended March 31, 2021, we experienced significant increases in average realized sales prices and sales volumes caused the following changes to our oil, NGL and natural gas revenues betweensales prices compared to the nine months ended September 30, 2017same period in 2020. Offsetting such price increases, winter storms during February 2021 disrupted both production activities and 2016:
(in thousands) Oil NGL Natural gas 
Total net
effect of change
2016 Revenues $218,478
 $37,850
 $34,145

$290,473
Effect of changes in average realized sales prices 64,985
 22,935
 14,583
 102,503
Effect of changes in sales volumes 30,412
 7,544
 7,199
 45,155
2017 Revenues $313,875
 $68,329
 $55,927
 $438,131
Oil revenue. Ourdrilling and completions operations, impacting total and oil revenue is a functionproduction for first-quarter 2021 by an estimated 5,700 BOE per day and 1,700 barrels of oil per day, respectively. Despite the weather impact, first-quarter 2021 oil production volumes soldwas positively impacted by our first package of wells in Howard County.
The following table presents midstream service revenues and average sales prices receivedof purchased oil for those volumes. The increase in oil revenue of $26.1 million, or 31%,the periods presented and the corresponding changes for such periods:
 
 		Three months ended March 31,2021 compared to 2020
(in thousands) 20212020Change ($)Change (%)
Midstream service revenues$1,296 $2,683 $(1,387)(52)%
Sales of purchased oil$46,477 $66,424 $(19,947)(30)%
Midstream service revenues. Our midstream service revenues decreased for the three months ended September 30, 2017March 31, 2021 compared to the same period in 2020. Midstream service revenues are generated by oil throughput fees and services provided to third parties for (i) integrated oil and natural gas gathering and transportation systems and related facilities, (ii) natural gas lift, fuel for drilling and completions activities and centralized compression infrastructure and (iii) water storage, recycling and transportation infrastructure, and are recognized over time as comparedthe customer benefits from these services when provided. These revenues fluctuate and will vary due to oil throughput fees and the level of services provided to third parties.
Sales of purchased oil. Sales of purchased oil are a function of the volumes and prices of purchased oil sold to customers and are offset by the volumes and costs of purchased oil. We are a firm shipper on both the Bridgetex and Gray Oak pipelines and we utilize purchased oil to fulfill portions of our commitments. We anticipate continuing this practice in the future. Sales of
30
purchased oil decreased during the three months ended September 30, 2016 is due to a 16% increase in average oil prices realized and a 13% increase in oil sales volumes.
The increase in oil revenue of $95.4 million, or 44%, for the nine months ended September 30, 2017 asMarch 31, 2021, compared to the nine months ended September 30, 2016 issame period in 2020 primarily due to decreased shipments of purchased oil on pipelines.
We enter into purchase transactions with third parties and separate sale transactions. These transactions are presented on a 26% increasegross basis as we act as the principal in average oil prices realizedthe transaction by assuming control of the commodities purchased and a 14% increase in oil sales volumes.
NGL revenue. Our NGL revenuethe responsibility to deliver the commodities sold. Revenue is a function of NGL production volumes sold and average sales prices received for those volumes. The increase in NGL revenue of $13.0 million, or 89%, for the three months ended September 30, 2017 as comparedrecognized when control transfers to the three months ended September 30, 2016 is due topurchaser/customer at the delivery point based on the price received. The transportation costs associated with these transactions are presented as a 61% increase in average NGL prices realizedcomponent of costs of purchased oil. See "—Costs and a 17% increase in NGL sales volumes.expenses - Costs of purchased oil."
The increase in NGL revenue of $30.5 million, or 81%, for the nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016 is due to a 51% increase in average NGL prices realized and a 20% increase in NGL sales volumes.
Natural gas revenue. Our natural gas revenue is a function of natural gas production volumes sold and average sales prices received for those volumes. The increase in natural gas revenue of $3.6 million, or 23%, for the three months ended September 30, 2017 as compared to the three months ended September 30, 2016 is due to a 24% increase in natural gas sales volumes partially offset by a 1% decrease in average natural gas prices realized.

The increase in natural gas revenue of $21.8 million, or 64%, for the nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016 is due to a 35% increase in average natural gas prices realized and a 21% increase in natural gas sales volumes.
Costs and expenses
The following table sets forthpresents information regarding costs and expenses and selected average costs and expenses per BOE sold for the periods presented:presented and the corresponding changes for such periods:
 Three months ended September 30, Nine months ended September 30, Three months ended March 31,2021 compared to 2020
(in thousands except for per BOE sold data) 2017 2016 2017
2016(in thousands except for per BOE sold data)20212020Change ($)Change (%)
Costs and expenses:  
  
  
  
Costs and expenses:  
Lease operating expenses $19,594
 $18,177
 $56,690
 $57,920
Lease operating expenses$18,918 $22,040 $(3,122)(14)%
Production and ad valorem taxes 9,558
 7,066
 26,811
 21,483
Production and ad valorem taxes13,283 9,244 4,039 44 %
Transportation and marketing expensesTransportation and marketing expenses12,127 13,544 (1,417)(10)%
Midstream service expenses 1,174
 1,039
 2,986
 2,826
Midstream service expenses858 1,170 (312)(27)%
Costs of purchased oil 47,385
 44,232
 141,661
 121,190
Costs of purchased oil49,916 79,297 (29,381)(37)%
General and administrative:        
Cash 16,034
 16,454
 45,728
 46,496
Non-cash stock-based compensation, net of amounts capitalized 8,966
 9,651
 26,877
 19,562
General and administrative (excluding LTIP)General and administrative (excluding LTIP)9,635 10,465 (830)(8)%
General and administrative (LTIP):General and administrative (LTIP):
LTIP cashLTIP cash1,620 133 1,487 1,118 %
LTIP non-cashLTIP non-cash1,818 1,964 (146)(7)%
Depletion, depreciation and amortization 41,212
 35,158
 113,327
 110,813
Depletion, depreciation and amortization38,109 61,302 (23,193)(38)%
Impairment expense —
 —
 —
 162,027
Impairment expense— 186,699 (186,699)(100)%
Other operating expenses 1,443
 2,465
 3,906
 4,169
Other operating expenses1,143 1,106 37 3 %
Total $145,366
 $134,242
 $417,986
 $546,486
Average costs per BOE sold(1):






    
Total costs and expensesTotal costs and expenses$147,427 $386,964 $(239,537)(62)%
Selected average costs and expenses per BOE sold(1):
Selected average costs and expenses per BOE sold(1):
Lease operating expenses
$3.55

$3.85

$3.64

$4.37
Lease operating expenses$2.66 $2.80 $(0.14)(5)%
Production and ad valorem taxes 1.73
 1.50
 1.72
 1.62
Production and ad valorem taxes1.87 1.17 0.70 60 %
Transportation and marketing expensesTransportation and marketing expenses1.71 1.72 (0.01)(1)%
Midstream service expenses 0.21
 0.22
 0.19
 0.21
Midstream service expenses0.12 0.15 (0.03)(20)%
General and administrative:        
Cash 2.90

3.49

2.94

3.51
Non-cash stock-based compensation, net of amounts capitalized 1.62

2.05

1.73

1.48
General and administrative (excluding LTIP)General and administrative (excluding LTIP)1.36 1.33 0.03 2 %
Total selected operating expensesTotal selected operating expenses$7.72 $7.17 $0.55 8 %
General and administrative (LTIP):General and administrative (LTIP):
LTIP cashLTIP cash$0.23 $0.02 $0.21 1,050 %
LTIP non-cashLTIP non-cash$0.26 $0.25 $0.01 4 %
Depletion, depreciation and amortization 7.46

7.45

7.28

8.36
Depletion, depreciation and amortization$5.36 $7.78 $(2.42)(31)%
Total $17.47

$18.56

$17.50

$19.55

(1)Selected average costs and expenses per BOE sold are based on actual amounts and are not calculated using the rounded numbers presented in the table above.
(1)Average costs per BOE sold are based on actual amounts and are not calculated using the rounded numbers presented in the table above.
Lease operating expenses. Lease operating expenses ("LOE"). LOE, which includeincludes workover expenses, increased by $1.4 million, or 8%, and LOE per BOE sold both decreased by $1.2 million, or 2%, for the three and nine months ended September 30, 2017, respectively,March 31, 2021, compared to the same periodsperiod in 2016. On a per BOE sold basis, lease operating2020. LOE are daily costs incurred to bring oil, NGL and natural gas out of the ground and to market, together with the daily costs incurred to maintain our producing properties. Such costs also include maintenance, repairs and non-routine workover expenses decreased 8%related to our oil and 17% for the three and nine months ended September 30, 2017, respectively, compared to the same periods in 2016 mainly due to previous investments in field infrastructure.natural gas properties. We continue to focus on economic efficiencies associated with the usage and procurement of products and services related to leaseLOE and decreasing failures and related workover expenses. We expect LOE to increase during 2021 due to higher expected operating expenses.costs on the wells coming on-line in Howard County compared to operating costs on our established acreage.
31
Production and ad valorem taxes. Production and ad valorem taxes increased by $2.5 million, or 35%, and $5.3 million, or 25%, for the three and nine months ended September 30, 2017, respectively,March 31, 2021, compared to the same periods in 2016. The quarter-over-quarter increase is due to a $1.5 million increase in production taxes and a $1.0 million increase in ad valorem taxes. The year-to-date increase over the comparable period in 2016 is due to a $6.6 million increase in production taxes partially offset by a $1.3 million decrease in ad valorem taxes.2020. Production taxes are based on and fluctuate in proportion to our oil, NGL and natural gas revenue.sales revenues, and are established by federal, state or local taxing authorities. We take full advantage of all credits and exemptions in our various taxing jurisdictions. Ad valorem taxes are based on and fluctuate in proportion to the taxable value assessed by the various counties where our oil and natural gas properties are located.
Midstream serviceTransportation and marketing expenses. See "—Results of operations - midstreamTransportation and marketing" for a discussion of these expenses.
Costs of purchased oil. See "—Results of operations - midstream and marketing" for a discussion of these expenses.

General and administrative ("G&A"). G&Amarketing expenses decreased by $1.1 million, or 4%, and increased by $6.5 million, or 10%, for the three and nine months ended September 30, 2017, respectively, compared to the same periods in 2016. The quarter-over-quarter decrease is mainly due to an overall reduction in employee-related costs, partially offset by an increase in professional fees for the three months ended September 30, 2017March 31, 2021, compared to the same period in 2016. The year-to-date increase over2020. These are costs incurred for the comparable perioddelivery of produced oil to customers in 2016 is mainly due to an increase in stock-based compensation, netthe U.S. Gulf Coast market via the Bridgetex pipeline and the Gray Oak pipeline. We ship the majority of amounts capitalized, resulting from a greater number performance share awards granted to a larger base of management and employees during the nine months ended September 30, 2017 comparedour produced oil to the same period in 2016.
The fair values for each of our restricted stock awards issued were calculated basedU.S. Gulf Coast, which we believe provides a long-term pricing advantage versus the Midland market. Additionally, firm transportation payments on the value of our stock price on the grant date in accordanceexcess pipeline capacity associated with GAAP and are being expensed on a straight-line basis over their associated requisite service periods. The fair values for each of our restricted stock option awards were determined using a Black-Scholes valuation model in accordance with GAAP and are being expensed on a straight-line basis over their associated four-year requisite service periods.
Our performance share awards are accounted for as equity awards andtransportation agreements are included in stock-based compensation expense. The fair values for each of our performance share awards issued were based on a projection of the performance of our stock price relative to a peer group, defined in each performance share award agreement, utilizing a forward-looking Monte Carlo simulation. The fair values for each of our performance share awards will not be re-measured after the initial grant-date valuationtransportation and are being expensed on a straight-line basis over the associated three-year requisite service periods.
marketing expenses. See Notes 2.n and 5Note 12.c to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our transportation commitments. We also recognized $2.0 million in marketing expense due to negative natural gas prices in March 2020.
Midstream service expenses. Midstream service expenses decreased for the three months ended March 31, 2021, compared to the same period in 2020. These are costs incurred to operate and maintain our (i) integrated oil and natural gas gathering and transportation systems and related facilities, (ii) centralized oil storage tanks, (iii) natural gas lift, fuel for drilling and completion activities and centralized compression infrastructure and (iv) water storage, recycling and transportation facilities.
Costs of purchased oil. Costs of purchased oil decreased for the three months ended March 31, 2021, compared to the same period in 2020 primarily due to decreased shipments of purchased oil on pipelines. We are a firm shipper on both the Bridgetex and Gray Oak pipelines and we utilize purchased oil to fulfill portions of our commitments. While our long-haul transportation capacity on the Bridgetex pipeline and Gray Oak pipeline is expected to exceed our net production, consistent with our historic practice, we expect to continue to purchase third-party oil at the trading hubs to satisfy the deficit in our associated long-haul transportation commitments.
General and administrative ("G&A"). G&A, excluding employee compensation expense from our long-term incentive plan ("LTIP"), decreased 8% for the three months ended March 31, 2021, compared to the same period in 2020, mainly due to a decrease in employee-related costs as a result of the measures taken during second-quarter 2020 to align our cost structure with operational activity, which included a workforce reduction.
LTIP cash expense increased for the three months ended March 31, 2021, compared to the same period in 2020. In 2020, we began utilizing cash awards for the majority of our employee base rather than equity awards. As such, in 2021 we expect LTIP cash expense to increase compared to 2020. LTIP non-cash expense decreased slightly for the three months ended March 31, 2021, compared to the same period in 2020. The decrease in LTIP non-cash expense was due to equity award forfeitures related to the second-quarter 2020 workforce reduction, which were still being expensed in first-quarter 2020, and was partially offset by a smaller population of 2021 equity awards granted. See Note 8 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for information regarding our stock-basedequity-based compensation.
Depletion, depreciation and amortization ("DD&A"). The following table sets forthpresents the components of our DD&A and depletion expense per BOE sold for the periods presented:
presented and the corresponding changes for such periods:
Three months ended March 31,2021 compared to 2020
 Three months ended September 30, Nine months ended September 30,
(in thousands except for per BOE sold data) 2017 2016 2017 2016
(in thousands)(in thousands)20212020Change ($)Change (%)
Depletion of evaluated oil and natural gas properties $37,538
 $31,679
 $102,290
 $100,136
Depletion of evaluated oil and natural gas properties$34,725 $57,752 $(23,027)(40)%
Depreciation of midstream service assets 2,241
 2,036
 6,569
 6,204
Depreciation of midstream service assets2,422 2,592 (170)(7)%
Depreciation and amortization of other fixed assets 1,433
 1,443
 4,468
 4,473
Depreciation and amortization of other fixed assets962 958 4 — %
Total DD&A $41,212
 $35,158
 $113,327
 $110,813
Total DD&A$38,109 $61,302 $(23,193)(38)%
Depletion expense per BOE soldDepletion expense per BOE sold$4.88 $7.33 $(2.45)(33)%
Both DD&A increased by $6.1 million, or 17%, and $2.5 million, or 2%, for the three and nine months ended September 30, 2017, respectively, compared to the same periods in 2016. The quarter-over-quarter increase is mainly due to an increase in production volumes solddepletion expense per BOE decreased for the three months ended September 30, 2017March 31, 2021, compared to the same period in 2016. On2020 as a per BOE sold basis, DD&A decreasedresult of the full cost impairments incurred during 2020. See Note 5 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report and "—Pricing and reserves" for additional information regarding the full cost method of accounting.
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Impairment expense.  The following table presents the components of our impairment expense for the nine months ended September 30, 2017 compared toperiods presented:
 Three months ended March 31,
(in thousands)20212020
Full cost ceiling impairment expense$— $177,182 
Midstream service asset impairment expense— 8,183 
Line-fill and other inventories impairment expense— 1,334 
Total impairment expense$— $186,699 
The unamortized cost of evaluated oil and natural gas properties did not exceed the same period in 2016, mainly due to positive well resultsfull cost ceiling as of March 31, 2021 and, the impact of ouras a result, we did not record a full cost ceiling impairment of $161.1 million recorded asfor such period. As of March 31, 2016.
Impairment expense. Our net book value2020, the unamortized cost of evaluated oil and natural gas properties exceeded the full cost ceiling amount as of March 31, 2016, and, as a result, we recorded a non-cash full cost ceiling impairment of $161.1 million. There were no comparable full cost ceiling impairments recorded during the nine months ended September 30, 2017. For further discussion of our non-cash full cost ceiling impairment accounting policy, see$177.2 million for such period. See Note 2.g5 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report. There were noReport and "—Pricing and reserves" for additional discussion of our full cost ceiling calculation.
Impairments are recorded on long-lived assets impairments recorded duringwhen indicators of impairment are present and the nine months ended September 30, 2017undiscounted cash flows estimated to be generated by those assets are less than the assets' carrying amount. Impairment is measured based on the excess of the carrying amount over the fair value of the asset. All inventory is carried at the lower of cost or 2016. Inventory impairments of $1.0 million were recorded forNRV, with cost determined using the nine months ended September 30, 2016. There were no inventory impairments recorded during the nine months ended September 30, 2017. For further discussion of long-lived assets and inventory impairment accounting policies, seeweighted-average cost method. See Note 2.i10.b to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.Report for additional discussion regarding the fair value measurement of our inventory and long-lived assets.

Other operating expenses. These costs include accretion expense due to the passage of time on our asset retirement obligations. See Note 2.k in our 2020 Annual report for additional information regarding our asset retirement obligations.
Non-operating income (expense)
The following table sets forthpresents the components of non-operating income (expense), net for the periods presented:
presented and the corresponding changes for such periods:
  Three months ended September 30, Nine months ended September 30,
(in thousands) 2017 2016 2017
2016
Non-operating income (expense):  
  
  
  
Gain (loss) on derivatives, net $(27,441) $6,850
 $38,127
 $(43,783)
Income from equity method investee (Note 16.a) 2,371
 265
 7,910
 6,259
Interest expense (23,697) (23,077) (69,590) (70,294)
Interest and other income 333
 33
 527
 143
Write-off of debt issuance costs —
 —
 —
 (842)
Loss on disposal of assets, net (991) (78) (400) (379)
Non-operating expense, net $(49,425) $(16,007) $(23,426) $(108,896)
 Three months ended March 31,2021 compared to 2020
(in thousands)20212020Change ($)Change (%)
Gain (loss) on derivatives, net$(154,365)$297,836 $(452,201)(152)%
Interest expense(25,946)(24,970)(976)(4)%
Loss on extinguishment of debt— (13,320)13,320 100 %
Loss on disposal of assets, net(72)(602)530 88 %
Other income, net1,379 91 1,288 1,415 %
Total non-operating income (expense), net$(179,004)$259,035 $(438,039)(169)%
Gain (loss) on derivatives, net. The following table presents the changes in the components of gain (loss) on derivatives, net for the periods presented:
presented and the corresponding changes for such periods:
(in thousands) Three months ended September 30, 2017 compared to 2016 Nine months ended September 30, 2017 compared to 2016
Changes in gain (loss) on derivatives, net:    
Fair value of derivatives outstanding $(3,619) $280,511
Cash settlements received for matured derivatives, net (30,672) (122,835)
Cash settlements received for early terminations of derivatives, net —
 (75,766)
Total changes in gain (loss) on derivatives, net $(34,291) $81,910
Three months ended March 31,2021 compared to 2020
(in thousands)20212020Change ($)Change (%)
Non-cash gain (loss) on derivatives, net$(122,232)$250,590 $(372,822)(149)%
Settlements (paid) received for matured derivatives, net(41,174)47,723 (88,897)(186)%
Premiums received (paid) for commodity derivatives9,041 (477)9,518 1,995 %
Gain (loss) on derivatives, net$(154,365)$297,836 $(452,201)(152)%
The changes in fair value ofNon-cash gain (loss) on derivatives, outstanding arenet is the result of (i) new early-terminated and expiringmatured contracts, including contingent consideration derivatives for the period subsequent to the acquisition date and through the end of the contingency period, and the changing relationship between our outstanding contract prices and the future market prices in the forward curves, which we use to calculate the fair value of our derivatives.derivatives and (ii) new and matured interest rate swaps and the changing relationship between the contract interest rate and the LIBOR interest rate forward curve. In general, if nooutstanding commodity contracts were entered into, terminated or modified,are held constant, we experience gains during periods of decreasing market prices and losses during periods of increasing
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market prices. Net cash settlementsSettlements paid or received for matured derivatives are for our commodity derivative contracts, which are based on the cash settlement prices of our matured derivatives compared to the prices specified in the derivative contracts.contracts, and for our interest rate derivative.
During the ninethree months ended September 30, 2017,March 31, 2021, we received proceeds fromcompleted a hedge restructuring inby (i) selling 2,254,500 calendar year 2021 $55.00 per barrel Brent ICE puts, which we early terminatedvolumetrically offset existing calendar year 2021 $55.00 per barrel Brent ICE puts, and receiving aggregate premiums of $9.0 million at inception of the contracts and (ii) entering into 2,254,500 calendar year 2021 Brent ICE swaps at a derivative contract swap, resulting in a termination amount due to usweighted-average price of $4.2 million. The $4.2 million was settled in full by applying$55.09 per barrel. Associated with the proceeds to pay the premium on one new derivative contract collaraforementioned existing calendar year 2021 $55.00 per barrel Brent ICE puts, which were entered into during 2020, are $50.6 million in aggregate premiums paid at the hedge restructuring.
During the nine months ended September 30, 2016, we received proceeds from a hedge restructuring in which we early terminated floors of certain derivative contract collars, resulting in a termination amount due to us of $80.0 million. The $80.0 million was settled in full by applying the proceeds to the premiums on two new derivative contracts entered into as partinception of the hedge restructuring.contacts.
See Notes 2.e, 79 and 8.a10.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report and "Item 3. Quantitative and Qualitative Disclosures About Market Risk" for additional information regarding our derivatives.
Income from equity method investee. See "—Results of operations - midstream and marketing" for a discussion of this income.
Interest expense. Interest expense increased by $0.6 million and decreased by $0.7 millionremained consistent for the three and nine months ended September 30, 2017, respectively, compared to the same periods in 2016. These changes are primarily due to fluctuations in the outstanding balance and floating interest rate on our Senior Secured Credit Facility.
Income tax. Since September 30, 2015, we have recorded a full valuation allowance against our net deferred tax position. As such, our effective tax rate was 0% during the three and nine months ended September 30, 2017 and 2016. For further discussion of our income tax position, see Note 6 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.

Results of operations - midstream and marketing
The following table presents selected financial information regarding our midstream and marketing operating segment for the periods presented:
  Three months ended September 30, Nine months ended September 30,
(in thousands) 2017 2016 2017 2016
Revenues:        
Natural gas sales $845
 $488
 $2,486
 $488
Midstream service revenues 16,892
 15,357
 52,630
 37,762
Sales of purchased oil 45,814
 42,441
 135,546
 116,670
Total revenues 63,551
 58,286
 190,662
 154,920
Costs and expenses:        
Midstream service expenses 12,474
 9,079
 34,686
 22,160
Costs of purchased oil 47,385
 44,232
 141,661
 121,190
General and administrative(1)
 2,038
 2,222
 6,079
 5,678
Depreciation and amortization(2)
 2,410
 2,275
 7,045
 6,669
Accretion of asset retirement obligations(3)
 57
 51
 165
 157
Operating income (loss) $(813) $427
 $1,026
 $(934)
Other financial information:        
Income from equity method investee $2,371
 $265
 $7,910
 $6,259
Interest expense(4)
 $1,513
 $1,446
 $4,340
 $4,310

(1)G&A expenses were allocated to the three months ended September 30, 2017, June 30, 2017, March 31, 2017, September 30, 2016, June 30, 2016 and March 31, 2016 based on the number of employees in the midstream and marketing segment as of the respective three-month period end dates. Certain components of G&A expenses, primarily payroll, deferred compensation and vehicle expenses, were not allocated but were actual expenses for the segment. Land and geology expenses were not allocated to the midstream and marketing segment.
(2)Depreciation and amortization were actual expenses for the midstream and marketing segment with the exception of the allocation of depreciation of other fixed assets, which was allocated to the three months ended September 30, 2017, June 30, 2017 and March 31, 2017 based on the number of employees in the midstream and marketing segment as of the respective three-month period end dates. Depreciation of other fixed assets was allocated to the three and nine months ended September 30, 2016 based on the number of employees in the midstream and marketing segment as of September 30, 2016. Certain components of depreciation and amortization of other fixed assets, primarily vehicles, were not allocated but were actual expenses for the segment.
(3)Accretion of asset retirement obligations were actual expenses and were not allocated.
(4)Interest expense for the three months ended September 30, 2017, June 30, 2017 and March 31, 2017 was allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of September 30, 2017, June 30, 2017 and March 31, 2017, respectively. Interest expense for the three and nine months ended September 30, 2016 was allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of September 30, 2016. Certain components of other fixed assets, primarily vehicles, were not allocated but were actual assets for the segment.
Natural gas sales. These revenues are related to our midstream and marketing segment providing our exploration and production segment with processed natural gas for use in the field. The corresponding cost component of these transactions are included in "Midstream service expenses." See Note 13 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information on our operating segments.
Midstream service revenues. Our midstream service revenues increased by $1.5 million and $14.9 million, or 10% and 39%, for the three and nine months ended September 30, 2017, respectively, compared to the same periods in 2016. These increases are mainly due to increased volume of water services provided.
Sales of purchased oil. Sales of purchased oil increased by $18.9 million, or 16%, for the nine months ended September 30, 2017March 31, 2021, compared to the same period in 2016 due to the increases in oil prices. For these sales of purchased oil, we

purchase oil from third parties in West Texas, transport it on the Bridgetex Pipeline2020. See Notes 6 and sell it to a third party in the Houston market. The net loss for the nine months ended September 30, 2017 compared to the same period in 2016 on these sales has increased by $1.6 million, or 35%, mainly due to the relative strengthening of the Midland market.
Midstream service expenses. Midstream service expenses increased by $3.4 million and $12.5 million, or 37% and 57%, for the three and nine months ended September 30, 2017, respectively, compared to the same periods in 2016. Midstream service expenses primarily represent costs incurred to operate and maintain our (i) oil and natural gas gathering and transportation systems and related facilities, (ii) centralized oil storage tanks, (iii) natural gas lift, rig fuel and centralized compression infrastructure and (iv) water storage, recycling and transportation facilities. These increases are due to the continued expansion of the midstream service component of our business.
Costs of purchased oil. Costs of purchased oil increased by $20.5 million, or 17%, for the nine months ended September 30, 2017 compared to the same period in 2016 primarily due to the increases in oil prices. These costs include purchasing oil from third parties and transporting it on the Bridgetex Pipeline.
Income from equity method investee. As of September 30, 2017, LMS owned 49% of the ownership units of Medallion. Subsequent to September 30, 2017, LMS and MMH consummated the sale of 100% of the ownership interests in Medallion to an affiliate of GIP. See Note 16.a18.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information regarding this sale.our long-term debt.
PriorLoss on extinguishment of debt. We recognized a loss on extinguishment of debt related to the sale, weaccounteddifference between the consideration for our investment in Medallion under the equity method of accounting with our proportionate share of net income reflected in the unaudited consolidated statements of operations as "Income from equity method investee"tender offers, early tender premiums and redemption prices and the net carrying amount reflected inamounts of the unaudited consolidated balance sheets as "Investment in equity method investee." Income from equity method investee increased by $2.1 millionextinguished January 2022 Notes and $1.7 million, or 795% and 26%, for the three and nine months ended September 30, 2017, respectively, compared to the same periods in 2016. The quarter-over-quarter increase is mainly due to Medallion's transportation fee revenue, resulting from higher throughput volumes partially offset by an increase in Medallion's operating expenses. The year-to-date increase over the comparable period in 2016 is mainly due to Medallion's transportation fee revenue, resulting from higher throughput volumes partially offset by increases in Medallion's depreciation and operating expenses. During the nine months ended September 30, 2017, Medallion continued expansion activities on existing portions of its pipeline infrastructure in order to gather additional third-party oil production. The Medallion pipeline system transported an average of 180,218 barrels of oil per day ("BOPD") and 118,000 BOPD forMarch 2023 Notes during the three months ended September 30, 2017 and 2016, respectively, and an average of 166,168 BOPD and 100,000 BOPD for the nine months ended September 30, 2017 and 2016, respectively.
March 31, 2020. See Note 2.h, 12.a and 16.a6.b to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information regarding the extinguishment of our January 2022 Notes and March 2023 Notes.
Loss on disposal of assets, net. Loss on disposal of assets, net, decreased for the three months ended March 31, 2021 compared to 2020. From time to time, we dispose of inventory, midstream service assets and other fixed assets. The associated gain or loss recorded during the period fluctuates depending upon the volume of the assets disposed, their associated net book value and, in the case of a disposal by sale, the sale price.
Income tax benefit (expense)
The following table presents income tax benefit (expense) for the periods presented and the corresponding changes for such periods:
Three months ended March 31,2021 compared to 2020
(in thousands)20212020Change ($)Change (%)
Deferred$762 $(2,417)$3,179 132 %
We are subject to federal and state income taxes and the Texas franchise tax. The deferred income tax benefit (expense) for the periods presented is attributed to deferred Texas franchise tax. As of March 31, 2021, we determined it was more likely than not that our federal and Oklahoma net deferred tax assets were not realizable through future net income. As of March 31, 2021, a total valuation allowance of $505.1 million has been recorded to offset our federal and Oklahoma net deferred tax assets, resulting in a Texas net deferred tax asset of $2.2 million. The effective tax rate for our operations was not meaningful for the periods presented and we expect it to remain at or under 1%, due to the full valuation allowance against our federal and Oklahoma net deferred tax assets.
Issuances, sales and/or exchanges of our common stock, taken together with prior transactions with respect to our common stock, could trigger an ownership change and therefore a limitation on our ability to utilize our NOL carryforwards which could result in taxable income in future years. For additional discussion of our income taxes, see Note 16 to our unaudited consolidated financial statements included elsewhere in this investment.Quarterly Report.
Liquidity and capital resources
OurHistorically, our primary sources of liquidity have been cash flows from operations, proceeds from equity offerings, proceeds from senior unsecured note offerings, borrowings under our Senior Secured Credit Facility and proceeds from asset dispositions. WeOur primary operational uses of capital have been for the acquisition, exploration and development of oil and natural gas properties and infrastructure development. While we cannot predict the duration and negative impact of
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COVID-19 and OPEC+ actions on the energy industry, we believe our cash flows from operations, (including our hedging program)favorable hedges and availability under our Senior Secured Credit Facility provide sufficient liquidity to manage our cash needs and contractual obligations and to fund our expected capital expenditures. Our primary operational uses of capital have been for the acquisition, exploration and development of oil and natural gas properties, LMS' infrastructure development and investments in Medallion.
On October 30, 2017, LMS, together with MMH, which is owned and controlled by an affiliate of EMG, completed the previously announced Medallion Sale to an affiliate of GIP, for cash consideration of $1.825 billion, subject to customary post-closing adjustments. LMS' net cash proceeds for its 49% ownership interest in Medallion are $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. 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 any such additional consideration will be paid.
A portion of the proceeds from the Medallion Sale was used to repay borrowings outstanding on our Senior Secured Credit Facility, and we have called for redemption all $500.0 million aggregate principal amount of our May 2022 Notes. See Notes 16.b and 16.c to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information.
In January 2017, we completed the sale of 2,900 net acres and working interests in 16 producing vertical wells in the Midland Basin to a third-party buyer for a purchase price of $59.7 million. After transaction costs reflecting an economic

effective date of October 1, 2016, the proceeds were $59.5 million, net of working capital and post-closing adjustments. We completed the closing adjustments for this divestiture in May 2017. A portion of these proceeds was used to pay down borrowings on our Senior Secured Credit Facility. The purchase price was recorded as an adjustment to oil and natural gas properties pursuant to the rules governing full cost accounting.
A significant portion of our capital expenditures can be adjusted and managed by us. We continually monitor the capital markets and our capital structure and consider which financing alternatives, including equitydebt and debtequity capital resources, joint ventures and asset sales, are available to meet our future planned capital expenditures, a significant portion of which we are able to adjust and manage. We also continually evaluate opportunities with respect to our capital structure, including issuances of new securities, as well as transactions involving our outstanding senior notes, which could take the form of open market or accelerated capital expenditures.private repurchases, exchange or tender offers, or other similar transactions, and our common stock, which could take the form of open market or private repurchases. We may make changes to our capital structure from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity and/or achieving cost efficiency. Such financing alternatives, including capital market transactions and debt repurchases,or combination of alternatives, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material. SeeWe continuously look for other opportunities to maximize shareholder value. For further discussion of our financing activities related to debt instruments, see Notes 36 and 418.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our divestiture ofReport.
Due to the inherent volatility in oil, NGL and natural gas propertiesprices and debt, respectively.
We continually seek to maintain a financial profile that provides operational flexibility. As of October 31, 2017, we had the full $1.0 billion borrowing base and aggregate elected commitment available for borrowings under our Senior Secured Credit Facility. We believe that our operating cash flow and the aforementioned liquidity sources provide us with the financial resources to implement our planned exploration and development activities.
We use derivatives to reduce exposure to fluctuationsdifferences in the prices of oil, NGL and natural gas. See Note 7.agas between where we produce and sell such commodities, we engage in commodity derivative transactions, such as puts, swaps, collars and basis swaps, to hedge price risk associated with a portion of our unaudited consolidated financial statements included elsewhereanticipated sales volumes. Due to the inherent volatility in this Quarterly Report for information regarding our derivative settlement indices and our open hedge positions as of September 30, 2017. As of November 2, 2017,interest rates, we have not entered into additional hedges subsequentan interest rate derivative swap to September 30, 2017.hedge interest rate risk associated with a portion of our anticipated outstanding debt under the Senior Secured Credit Facility. We will pay a fixed rate over the contract term for that portion. By removing a significant portion of the (i) price volatility associated with future production,sales volumes and (ii) interest rate volatility associated with anticipated outstanding debt, we expect to mitigate, but not eliminate, the potential effects of variability in cash flows from operations due to fluctuations in commodity prices. Our derivative positions will help us stabilize a portion of our expected cash flows from operations in the event of future declines in the prices of oil, NGL and natural gas.operations. See "Item"Part I. Item 3. Quantitative and Qualitative Disclosures About Market Risk" below.
See Note 9.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for discussion of our commodity hedge restructuring during the three months ended March 31, 2021 and corresponding summary of open commodity derivative positions as of March 31, 2021 for commodity derivatives that were entered into through March 31, 2021.
We continually seek to maintain a financial profile that provides operational flexibility. As of March 31, 2021, we had cash and cash equivalents of $44.3 million and available capacity under the Senior Secured Credit Facility, after the reduction for outstanding letters of credit, of $460.9 million, resulting in total liquidity of $505.2 million. As of May 3, 2021, we had cash and cash equivalents of $48.4 million and available capacity under the Senior Secured Credit Facility, after the reduction for outstanding letters of credit, of $450.9 million, resulting in total liquidity of $499.3 million. We believe that our operating cash flows and the aforementioned liquidity sources provide us with the financial resources to manage our business needs, to implement our currently planned capital expenditure budget and, at our discretion, to fund any share repurchases, pay down, repurchase or refinance debt or adjust our planned capital expenditure budget.
Cash flows
OurThe following table presents our cash flows for the periods presented are summarized inand the table below:
corresponding changes for such periods:
 Nine months ended September 30, Three months ended March 31,2021 compared to 2020
(in thousands) 2017 2016(in thousands)20212020Change ($)Change (%)
Net cash provided by operating activities $272,051
 $245,454
Net cash provided by operating activities$71,151 $109,589 $(38,438)(35)%
Net cash used in investing activities (356,893) (455,895)Net cash used in investing activities(69,020)(159,791)90,771 57 %
Net cash provided by financing activities 72,988
 209,647
Net decrease in cash and cash equivalents $(11,854) $(794)
Net cash (used in) provided by financing activitiesNet cash (used in) provided by financing activities(6,626)72,122 (78,748)(109)%
Net (decrease) increase in cash and cash equivalentsNet (decrease) increase in cash and cash equivalents$(4,495)$21,920 $(26,415)(121)%
Cash flows from operating activities
Net cash provided by operating activities increased by $26.6 million fordecreased during the ninethree months ended September 30, 2017March 31, 2021, compared to the same period in 20162020. Notable cash changes include (i) a decrease of $79.4 million due to changes in net settlements for matured derivatives, net of premiums, mainly due to the price-relatedincreases in commodity prices, (ii) an increase in total oil, NGL and natural gas revenues; however, notable cash changes included (i) a decrease
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Table of $125.2Contents
sales revenues of $66.6 million in cash settlements received for matured and early terminations of derivatives, net of premiums paid, (ii) a cash outflow of $6.4 million related to the settlement of our last tranche of performance unit awards in first-quarter 2016 with no comparable amount incurred in 2017 and (iii) a decrease of $33.0 million due to net changes in working capital outflowsoperating assets and liabilities. Other significant changes include a decrease in costs of $1.2 million.purchased oil partially offset by sales of purchased oil and transportation and marketing expenses. The increase in total oil, NGL and natural gas sales revenues was due to a 65% increase in average sales price per BOE and was partially offset by a 10% decrease in total volumes sold. For additional information, see "—Results of operations."
Our operating cash flows are sensitive to a number of variables, the most significant of which are the volatility of oil, NGL and natural gas prices, mitigated to the extent of our commodity derivatives' exposure, and productionsales volume levels. Regional and worldwide economic activity, weather, infrastructure, transportation capacity to reach markets, costs of operations, legislation and regulations, including potential government production curtailments, and other variable factors significantly impact the prices of these commodities. Commodity prices have been most impacted by the effects of COVID-19 on demand and the effects of the OPEC+ actions, and earlier in the year, related transportation and storage constraints, particularly in the State of Texas, on supply. These factors are not within our control and are difficult to predict. For additional information on the impact of changing prices onrisks related to our financial position,business, see "Item"Part I. Item 3. Quantitative and Qualitative Disclosures About Market Risk."Risk" and "Part II. Item 1A. Risk Factors" included elsewhere in this Quarterly Report and "Part I. Item 1A. Risk Factors" in our 2020 Annual Report.
Cash flows from investing activities
Net cash used in investing activities decreased $99.0 million duringfor the ninethree months ended September 30, 2017March 31, 2021, compared to the same period in 2016 and is2020, mainly attributabledue to (i) proceeds we received from a January 2017 divestiture of oil and natural gas properties and (ii) a decrease in contributions made to Medallion. The year-over-year increase in total capital expenditures for oil and natural gas properties midstream service assets and other fixed assets was substantially offset by cash

outflow for 2016a decrease in acquisitions of oil and natural gas properties. See Note 3 to our unaudited consolidated financial statements included elsewhere in thisthe Quarterly Report for additional discussion of our acquisitions of oil and natural gas properties.
The following table presents the January 2017 divestiture and the 2016 acquisitions.
Our netcomponents of our cash used inflows from investing activities for the periods presented is summarizedand the corresponding changes for such periods:
 Three months ended March 31,2021 compared to 2020
(in thousands)20212020Change ($)Change (%)
Acquisitions of oil and natural gas properties, net$— $(22,876)$22,876 100 %
Capital expenditures:
Oil and natural gas properties(68,329)(135,376)67,047 50 %
Midstream service assets(329)(761)432 57 %
Other fixed assets(551)(829)278 34 %
Proceeds from dispositions of capital assets, net of selling costs189 51 138 271 %
Net cash used in investing activities$(69,020)$(159,791)$90,771 57 %
The following table presents the components of our costs incurred, excluding non-budgeted acquisition costs, for the periods presented and the corresponding changes for such periods:
Three months ended March 31,2021 compared to 2020
(in thousands)20212020Change ($)Change (%)
Oil and natural gas properties$68,449 $152,868 $(84,419)(55)%
Midstream service assets876 923 (47)(5)%
Other fixed assets600 823 (223)(27)%
Total costs incurred, excluding non-budgeted acquisition costs$69,925 $154,614 $(84,689)(55)%
See Note 5 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information regarding our costs incurred in the table below:
  Nine months ended September 30,
(in thousands) 2017 2016
Capital expenditures:    
Acquisitions of oil and natural gas properties $—
 $(115,600)
Oil and natural gas properties (381,165) (276,735)
Midstream service assets (11,680) (4,231)
Other fixed assets (3,604) (982)
Investment in equity method investee (Note 16.a) (24,572) (58,712)
Proceeds from dispositions of capital assets, net of selling costs 64,128
 365
Net cash used in investing activities $(356,893) $(455,895)
Capital expenditure budget
During the fourth quarterexploration and development of 2017, our board of directors approved an increase to the 2017 capital expenditure budget of $100.0 million which represents service cost inflation, additional completion optimization testingoil and data collection. Our revised capital expenditure budget is $630.0 million for calendar year 2017, excluding acquisitions and investments in Medallion. We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted.natural gas properties.
The amount, timing and allocation of capital expenditures are largely discretionary and within management's control. If oil, NGL and natural gas prices declineare below our acceptable levels, or costs increaseare above our acceptable levels, we may choose to defer a portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash
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flow. Subject to financing alternatives, we may also increase our capital expenditures significantly to take advantage of opportunities we consider to be attractive. We consistentlycontinually monitor and may adjust our projected capital expenditures in response to world developments, such as those we experienced in 2020, as well as success or lack of success in drilling activities, changes in prices, availability of financing and joint venture opportunities, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs and supplies, changes in service costs, contractual obligations, internally generated cash flow and other factors both within and outside our control. For additional information on the impact of changing prices on our financial position, see "Item 3. Quantitative and Qualitative Disclosures About Market Risk."
Cash flows from financing activities
For the nine months ended September 30, 2017, our netNet cash (used in) provided by financing activities wasdecreased for the result of borrowings onthree months ended March 31, 2021, compared to the same period in 2020. Notable 2021 activity includes proceeds from our Senior Secured Credit Facility partially offset by (i)ATM Program and net payments on our Senior Secured Credit Facility, (ii)Facility. Notable 2020 activity includes the purchase of treasury stock to satisfy employees' tax withholding upon vesting of their stock-based compensation awards and (iii) payments for debt issuance costs as a result of entering into the Fifth Amended and Restated Credit Agreement to our Senior Secured Credit Facility. The aforementioned increase in the purchase of treasury stock is mainly due to the increase of our stock price at the restricted stock awards' vest dates, which is utilized to determine the taxable compensation, compared to our stock price at the restricted stock awards' grant dates, which is utilized to determine the number of shares of restricted stock awards to be granted. For the nine months ended September 30, 2016, our primary sources of cash provided by financing activities were borrowings on our Senior Secured Credit FacilityJanuary 2025 Notes and proceeds from our July 2016 Equity Offering and May 2016 Equity Offering,January 2028 Notes, partially offset by the extinguishment of our January 2022 Notes and March 2023 Notes and payments on our Senior Secured Credit Facility. For further discussion of our financing activities related to debt instruments, see Notes 6 and 18.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.

Our netThe following table presents the components of our cash provided byflows from financing activities for the periods presented is summarized in the table below:
  Nine months ended September 30,
(in thousands) 2017 2016
Borrowings on Senior Secured Credit Facility $155,000
 $214,682
Payments on Senior Secured Credit Facility (70,000) (279,682)
Proceeds from issuance of common stock, net of offering costs —
 276,052
Purchase of treasury stock (7,638) (1,613)
Proceeds from exercise of stock options 358
 208
Payments for debt issuance costs (4,732) —
Net cash provided by financing activities $72,988
 $209,647
Debt
As of September 30, 2017, we were a party only to our Senior Secured Credit Facility and the indentures governing our senior unsecured notes.corresponding changes for such periods:
As of September 30, 2017, we had $1.5 billion in debt outstanding, $845.0 million available for borrowings
 Three months ended March 31,2021 compared to 2020
(in thousands)20212020Change ($)Change (%)
Borrowings on Senior Secured Credit Facility$15,000 $— $15,000 100 %
Payments on Senior Secured Credit Facility(50,000)(100,000)50,000 50 %
Issuance of January 2025 Notes and January 2028 Notes— 1,000,000 (1,000,000)(100)%
Extinguishment of debt— (808,855)808,855 100 %
Proceeds from issuance of common stock, net of costs26,866 — 26,866 100 %
Stock exchanged for tax withholding(1,290)(640)(650)(102)%
Payments for debt issuance costs— (18,383)18,383 100 %
Other liabilities2,798 — 2,798 100 %
Net cash (used in) provided by financing activities$(6,626)$72,122 $(78,748)(109)%
We are the borrower under our Senior Secured Credit Facility and $20.8 million in cash on hand for total available liquidity of $865.8 million. On October 30, 2017, we used a portion ofparty to the proceeds from the Medallion Sale to repay borrowings outstanding underindentures governing our Senior Unsecured Notes.
Senior Secured Credit Facility.
On October 30, 2017, we issued a press release announcing that we have called for redemption all $500.0 million aggregate principal amount of our May 2022 Notes. The redemption date for the May 2022 Notes is November 29, 2017, and holders will receive a redemption price of 103.688% of the principal amount of the May 2022 Notes, plus accrued and unpaid interest from November 1, 2017 through November 28, 2017.Facility
As of OctoberMarch 31, 2017, we had $1.3 billion in debt outstanding, $1.0 billion available for borrowings under our2021, the Senior Secured Credit Facility, and $735.0 million in cashwhich matures on hand for total available liquidity of $1.7 billion. The cash on hand amount includes proceeds from the Medallion Sale prior to the redemption of the May 2022 Notes, which is expected to be completed on November 29, 2017.
Senior Secured Credit Facility. As of September 30, 2017, our Senior Secured Credit FacilityApril 19, 2023, had a maximum credit amount of $2.0 billion, a borrowing base and an aggregate elected commitment of $725.0 million each, of $1.0 billionwith $220.0 million outstanding, and $155.0 million outstanding.
The borrowing base under our Senior Secured Credit Facility iswas subject to a semi-annual redetermination based on the lenders' evaluationan interest rate of our oil, NGL and natural gas reserves.2.625%. The lenders have the right to call for an interim redetermination of the borrowing base once between any two redetermination dates and in other specified circumstances. The maturity date of the Senior Secured Credit Facility is May 2, 2022, provided that if either of the January 2022 Notes or May 2022 Notes have not been redeemed or refinanced on or prior to the applicable Early Maturity Date, the Senior Secured Credit Facility will mature on such Early Maturity Date.
On October 20, 2017, pursuant to a regular semi-annual redetermination, the lenders reaffirmed the $1.0 billion borrowing base under our Senior Secured Credit Facility. Our aggregate elected commitment of $1.0 billion remained unchanged.
Principal amounts borrowed under our Senior Secured Credit Facility are payable on the final maturity date with such borrowings bearing interest that is payable, at our election, either on the last day of each fiscal quarter at an Adjusted Base Rate or at the end of one-, two-, three-, six- or, to the extent available, 12-month interest periods (and in the case of six- and 12-month interest periods, every three months prior to the end of such interest period) at an Adjusted London Interbank Offered Rate, in each case, plus an applicable margin, which ranges from 1.0% to 2.0% for Adjusted Base Rate loans and from 2.0% to 3.0% for Adjusted London Interbank Offered Rate loans, based on the ratio of the outstanding revolving credit on our Senior Secured Credit Facility to the elected commitment. We are also required to pay an annual commitment fee based on the unused portion of the bank's commitment of 0.375% to 0.5%.
Our Senior Secured Credit Facility is secured by a first-priority lien on certain of our assets, including oil and natural gas properties constituting at least 85% of the present value of our proved reserves owned now or in the future. Our Senior Secured Credit Facility contains both financial and non-financial covenants. Wecovenants, all of which we were in compliance with these covenantsfor all periods presented. Additionally, the Senior Secured Credit Facility provides for the issuance of letters of credit, limited to the lesser of total capacity or $80.0 million. As of March 31, 2021 and December 31, 2020, we had one letter of credit outstanding of $44.1 million under the Senior Secured Credit Facility. The Senior Secured Credit Facility is fully and unconditionally guaranteed by LMS and GCM. On April 6, 2021 and April 26, 2021, we borrowed an additional $20.0 million and made a $10.0 million payment, respectively, on the Senior Secured Credit Facility. As a result, the outstanding balance under the Senior Secured Credit Facility was $230.0 million as of September 30, 2017.May 3, 2021.

Senior unsecured notes. The following table presents principal amountsSee Notes 6.c and applicable interest rates for our outstanding senior unsecured notes as of September 30, 2017:
(in millions, except for interest rates) Principal Interest rate
January 2022 Notes $450.0
 5.625%
May 2022 Notes 500.0
 7.375%
March 2023 Notes 350.0
 6.250%
Total Senior Unsecured Notes $1,300.0
  
Refer18.a to Notes 4, 16.b and 16.c of our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of the March 2023 Notes, January 2022 Notes, May 2022 Notes and our Senior Secured Credit Facility.

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January 2025 Notes and January 2028 Notes
The following table presents principal amounts and applicable interest rates for our outstanding January 2025 Notes and January 2028 Notes (together the "Senior Unsecured Notes") as of March 31, 2021:
(in millions, except for interest rates)PrincipalInterest rate
January 2025 Notes$577.9 9.500 %
January 2028 Notes361.0 10.125 %
Total Senior Unsecured Notes$938.9 
The net proceeds from the January 2025 Notes and January 2028 Notes were used to fund the tender offers and redemptions of the remaining principle amounts of the January 2022 Notes and March 2023 Notes. See Notes 6.a and 6.b to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of our senior unsecured notes.
Supplemental Guarantor information
As discussed in Note 6.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report, on January 24, 2020, we issued $600.0 million in aggregate principal amount of the January 2025 Notes and $400.0 million in aggregate principal amount of the January 2028 Notes. As of March 31, 2021, $938.9 million of our Senior Unsecured Notes remained outstanding. Each of our wholly owned subsidiaries, LMS and GCM (each, a "Guarantor," and together, the "Guarantors"), jointly and severally, and fully and unconditionally, guarantees the January 2025 Notes and the January 2028 Notes. We do not have any non-guarantor subsidiaries.
The guarantees are senior unsecured obligations of each Guarantor and rank equally in right of payment with other existing and future senior indebtedness of such Guarantor, and senior in right of payment to all existing and future subordinated indebtedness of such Guarantor. The guarantees of the Senior Unsecured Notes by the Guarantors are subject to certain Releases. The obligations of each Guarantor under its note guarantee are limited as necessary to prevent such note guarantee from constituting a fraudulent conveyance under applicable law. Further, the rights of holders of the Senior Unsecured Notes against the Guarantors may be limited under the U.S. Bankruptcy Code or state fraudulent transfer or conveyance law. Laredo is not restricted from making investments in the Guarantors and the Guarantors are not restricted from making intercompany distributions to Laredo or each other.
As we do not have any non-guarantor subsidiaries, the assets, liabilities and results of operations of the combined issuer and Guarantors are not materially different than the corresponding amounts presented in our unaudited consolidated financial statements included elsewhere in this Quarterly Report. Accordingly, we have omitted the summarized financial information of the issuer and the Guarantors that would otherwise be required.
Obligations and commitments
As of September 30, 2017, ourOur significant contractual obligations includedand commitments include our March 2023Senior Unsecured Notes, January 2022 Notes, May 2022 Notes, Senior Secured Credit Facility, drilling contract commitments, firm sale and transportation commitments, derivative deferred premiums,Senior Secured Credit Facility, asset retirement obligations and office and equipment leases. Fromlease commitments. Since December 31, 2016 to September 30, 2017, the2020, there have been no material changes inother than to our contractual obligations included (i) an increase of $85.0 million in outstanding borrowings on our Senior Secured Credit Facility, (ii) a decrease of $71.6 million in ourdebt and firm sale and transportation commitments, (iii) a decrease of $65.6 million on our interest obligations for our senior unsecured notes as semi-annual interest payments were made in January, March, May, Julycommitments. See Notes 6 and September of 2017, (iv) an increase of $18.8 million in deferred premiums mainly due to new derivative contracts and (v) a decrease of $4.9 million for drilling contract commitments (on contracts other than those on a well-by-well basis).
Refer to Notes 2, 4, 7, 8, 11, 16.b and 16.c18.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our debt.
We have committed to deliver, for sale or transportation, fixed volumes of product under certain contractual obligations.arrangements that specify the delivery of a fixed and determinable quantity. If not fulfilled, we are subject to firm transportation payments on excess pipeline capacity and other contractual penalties. Future firm sale and transportation commitments of $258.8 million are expected to be satisfied as of March 31, 2021 and are not recorded as a liability on the unaudited consolidated balance sheet. These commitments have decreased during the three months ended March 31, 2021, and are mainly due to our fulfillment of contractual commitments, partially offset by changes to existing sales commitments. Of this amount, $77.7 million is related to transportation commitments with a certain pipeline pertaining to the gathering of our production from our established acreage that extends into 2024. We believe we will be able to meet the majority of this commitment, however, as development plans evolve and refine, we may be unable to meet a portion of this commitment. For the three months ended March 31, 2021, we were unable to satisfy a portion of this particular commitment with produced or purchased oil and,as such, expensed firm transportation payments on excess capacity of $1.6 million. See Note 12.c to our
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unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our firm sale and transportation commitments.
Non-GAAP financial measuremeasures
The non-GAAP financial measuremeasures of Free Cash Flow and Adjusted EBITDA, as defined by us, may not be comparable to similarly titled measures used by other companies. Therefore, thisthese non-GAAP measurefinancial 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 flowflows from operating activities. Free Cash Flow 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
Free Cash Flow is a non-GAAP financial measure that we define as net cash provided by operating activities (GAAP) before changes in operating assets and liabilities, net, less costs incurred, excluding non-budgeted acquisition costs. Free Cash Flow 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 Free Cash Flow (non-GAAP) for the periods presented:
Three months ended March 31,
(in thousands)20212020
Net cash provided by operating activities$71,151 $109,589 
Less:
Change in current assets and liabilities, net(17,259)18,708 
Change in noncurrent assets and liabilities, net(3,275)(6,210)
Cash flows from operating activities before changes in operating assets and liabilities, net91,685 97,091 
Less costs incurred, excluding non-budgeted acquisition costs:
Oil and natural gas properties(1)
68,449 152,868 
Midstream service assets(1)
876 923 
Other fixed assets600 823 
Total costs incurred, excluding non-budgeted acquisition costs69,925 154,614 
Free Cash Flow (non-GAAP)$21,760 $(57,523)

(1)Includes capitalized share-settled equity-based compensation and asset retirement costs.

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Adjusted EBITDA
Adjusted EBITDA is a non-GAAP financial measure that we define as net income or loss (GAAP) plus adjustments for deferred income tax expense or benefit,share-settled equity-based compensation, 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 or received for commodity derivatives interestthat matured during the period, accretion expense, write-off of debt issuance costs, gains or losses on disposal of assets, interest expense, income or loss from equity method investee, proportionate Adjusted EBITDA of equity method investeetaxes and other non-recurring income and expenses. Adjusted EBITDA provides no information regarding a company’scompany's capital structure, borrowings, interest costs, capital expenditures, working capital movement or tax position. Adjusted EBITDA does not represent funds available for future discretionary use because thoseit excludes 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, whichthat 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 anddue 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): for the periods presented:
 Three months ended September 30,
Nine months ended September 30, Three months ended March 31,
(in thousands) 2017
2016
2017
2016(in thousands)20212020
Net income (loss) $11,027

$9,485

$140,413

$(242,318)Net income (loss)$(75,439)$74,646 
Plus:    
 

 
Plus:
Share-settled equity-based compensation, netShare-settled equity-based compensation, net2,068 2,376 
Depletion, depreciation and amortization 41,212

35,158

113,327

110,813
Depletion, depreciation and amortization38,109 61,302 
Impairment expense
—

—

—

162,027
Impairment expense— 186,699 
Non-cash stock-based compensation, net of amounts capitalized 8,966

9,651

26,877

19,562
Accretion expense 951

883

2,822

2,587
Mark-to-market on derivatives:    





Mark-to-market on derivatives:
(Gain) loss on derivatives, net
27,441

(6,850)
(38,127)
43,783
(Gain) loss on derivatives, net154,365 (297,836)
Cash settlements received for matured derivatives, net
13,635

44,307

34,791

157,626
Cash settlements received for early terminations of derivatives, net
—

—

4,234

80,000
Cash premiums paid for derivatives (1,448)
(2,709)
(13,542)
(86,972)
Settlements (paid) received for matured derivatives, netSettlements (paid) received for matured derivatives, net(41,174)47,723 
Net premiums paid for commodity derivatives that matured during the period(1)
Net premiums paid for commodity derivatives that matured during the period(1)
(11,005)(477)
Accretion expenseAccretion expense1,143 1,106 
Loss on disposal of assets, netLoss on disposal of assets, net72 602 
Interest expense 23,697

23,077

69,590

70,294
Interest expense25,946 24,970 
Write-off of debt issuance costs —

—

—

842
Loss on disposal of assets, net
991

78

400

379
Income from equity method investee (2,371) (265) (7,910) (6,259)
Proportionate Adjusted EBITDA of equity method investee(1)
 6,789
 5,194
 19,755
 13,981
Adjusted EBITDA $130,890

$118,009

$352,630

$326,345
Loss on extinguishment of debtLoss on extinguishment of debt— 13,320 
Income tax (benefit) expenseIncome tax (benefit) expense(762)2,417 
Adjusted EBITDA (non-GAAP)Adjusted EBITDA (non-GAAP)$93,323 $116,848 

(1)Reflects net premiums paid previously or upon settlement that are attributable to derivatives settled in the respective periods presented.
(1)
Proportionate Adjusted EBITDA of Medallion, our equity method investee, is calculated as follows:

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  Three months ended September 30, Nine months ended September 30,
(in thousands) 2017 2016 2017
2016
Income from equity method investee $2,371
 $265
 $7,910
 $6,259
Adjusted for proportionate share of:      
  
Depreciation and amortization 4,418
 4,929
 11,845
 7,722
Proportionate Adjusted EBITDA of equity method investee $6,789
 $5,194
 $19,755
 $13,981
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Critical accounting policies and estimates
The discussion and analysis of our financial condition and results of operations are based upon our unaudited consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our unaudited consolidated financial statements. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our unaudited consolidated financial statements.

In management's opinion, the more significant reporting areas impacted by our judgments and estimates are (i) the choice of accounting method for oil and natural gas activities, (ii) estimation of oil, NGL and natural gas reserve quantities and standardized measure of future net revenues, (iii) impairment of oil and natural gas properties, (iv) revenue recognition, (v) estimation of income taxes, (vi) asset retirement obligations, (vii) valuation of derivatives and deferred premiums, (viii) valuation of stock-based compensation, (ix) fair value of assets acquired and liabilities assumed in an acquisition and (x) estimates of contingent liabilities. Management's judgments and estimates in these areas are based on information available from both internal and external sources, including engineers, geologists and historical experience in similar matters. Actual results could differ from these estimates as additional information becomes known.
There have been no material changes in our critical accounting policies and procedures during the ninethree months ended September 30, 2017. ForMarch 31, 2021. See our other critical accounting policies and procedures, please see our disclosure of critical accounting policies in "Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" of the 20162020 Annual Report. Additionally,
New accounting standards
For discussion of new accounting standards, see Note 2 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for a discussion of additional accounting policies and estimates made by management.
Recent accounting pronouncements
See Note 15 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for information regarding recent accounting pronouncements.Report.
Off-balance sheet arrangements
Currently, we do not have any off-balance sheet arrangements other than operating leases, drilling contracts andour firm sale and transportation commitments, which are described in "—Obligations and commitments."commitments" and certain operating leases with a term less than or equal to 12 months. See Note 11Notes 4 and 12 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information.information on our leases and commitments and contingencies, respectively.



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Item 3.    Quantitative and Qualitative Disclosures About Market Risk
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term "market risk," in our case, refers to the risk of loss arising from adverse changes in oil, NGL and natural gas prices and in interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitiverisk-sensitive derivative instruments were entered into for hedging purposes, rather than for speculative trading.
CommodityOil, NGL and natural gas price exposure
Due to the inherent volatility in oil, NGL and natural gas prices and differences in the prices of oil, NGL and natural gas between where we use derivatives,produce and sell such commodities, we engage in commodity derivative transactions, such as puts, swaps, collars and basis swaps, and call spreads to hedge price risk associated with a significant portion of our anticipated production.sales volumes. By removing a portion of the price volatility associated with future production,sales volumes, we expect to reduce,mitigate, but not eliminate, the potential effects of variability in cash flows from operations due to fluctuations inoperations.
The fair values of our open commodity prices. We have not elected hedge accounting on these derivatives and therefore, the gains and losses on opencontingent consideration derivative positions are reflected in earnings. At each period end, we estimatelargely determined by the relevant forward commodity price curves of the indexes associated with our open derivative positions. We had a $156.9 million net liability position from the fair values of our open commodity derivatives using an independent third-party valuation and recognizea $1.1 million liability position from the associated gain or loss in our unaudited consolidated statements of operations included elsewhere in this Quarterly Report.
The fair valuesvalue of our derivatives are largely determined by estimatespotential contingent consideration payments associated with an asset acquisition, each as of March 31, 2021. The following table provides a sensitivity analysis of the forward curvesprojected incremental effect on income (loss) before income taxes of the relevant price indices. As of September 30, 2017, a hypothetical 10% change in the relevant forward commodity price curves of the indexes associated with our derivatives would have changed our netopen commodity and contingent consideration derivative positions to the following amounts:
as of March 31, 2021:
(in thousands) 10% Increase 10% Decrease(in thousands)10% Increase 10% Decrease
Derivatives $(17,128) $51,649
CommodityCommodity$(82,555)$82,096 
Contingent considerationContingent consideration(7)25 
TotalTotal$(82,562)$82,121 
As of September 30, 2017See Notes 9.a, 9.c, 10.a and December 31, 2016, the net fair values of our open derivative contracts were $15.4 million and $3.0 million, respectively. Refer18.b to Notes 2.e, 7 and 8.a of our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional disclosures regardingfurther discussion of our commodity and contingent consideration derivatives.
Interest rate risk
Our Senior Secured Credit Facility bears interest at a floating rate and our notes bear interest at fixed rates. The expected maturity years, carrying amountsoutstanding balances and fixed interest rates on our long-term debt as of September 30, 2017 andMarch 31, 2021 were as follows:
 Maturity year
(in millions except for interest rates)20232025Thereafter
January 2025 Notes$— $577.9 $— 
Fixed interest rate— %9.500 %— %
January 2028 Notes$— $— $361.0 
Fixed interest rate— %— %10.125 %
Senior Secured Credit Facility$220.0 $— $— 
Floating interest rate2.625 %— %— %
Due to the inherent volatility in interest rates, we have entered into an interest rate derivative swap to hedge interest rate risk associated with a portion of our anticipated outstanding debt under the Senior Secured Credit Facility's average floatingFacility. We will pay a fixed rate over the contract term for that portion. By removing a portion of the interest rate forvolatility associated with anticipated outstanding debt, we expect to mitigate, but not eliminate, the nine months ended September 30, 2017 were as follows:potential effects of variability in cash flows from operations.

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  Expected maturity year
(in millions except for interest rates) 2022 2023
Senior Secured Credit Facility - floating rate $155.0
 $—
Average interest rate 2.826% —%
January 2022 Notes - fixed rate $450.0
 $—
Interest rate 5.625% —%
May 2022 Notes - fixed rate $500.0
 $—
Interest rate 7.375% —%
March 2023 Notes - fixed rate $—
 $350.0
Interest rate —% 6.250%
The fair value of our open interest rate derivative position is largely determined by the LIBOR interest rate forward curve associated with our open position. We had a $0.2 million total liability position from the net fair value of our open interest rate derivative as of March 31, 2021. The following table provides a sensitivity analysis of the projected incremental effect on income (loss) before income taxes of a hypothetical 1% incremental addition to or subtraction from the relevant LIBOR forward curve interest rates associated with our open interest rate derivative position as of March 31, 2021:
(in thousands)1% incremental addition to 1% incremental subtraction from
Interest rate$1,082 $(1,082)
See Notes 6, 10.c and 18.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of our debt. See Notes 9.b and 10.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of our interest rate derivative.
Counterparty and customer credit risk
As of September 30, 2017,We use commodity and interest rate derivatives to hedge our principal exposuresexposure to commodity prices and interest rate volatility, respectively. These transactions expose us to potential credit risk were through receivables of (i) $62.1 million from sales of our oil, NGL and natural gas production that we market to energy marketing companies and refineries, (ii) $20.0 million from the fair values of our open derivative contracts, (iii) $15.6 million from sales of purchased oil and other products, (iv) $8.7 million from joint-interest partners and (v) $3.3 million from matured derivatives.
We are subject to credit risk due to the concentration of (i) our oil, NGL and natural gas receivables with several significant customers and (ii) our sales of purchased oil receivable with one customer. On occasion we require our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.
counterparties. We have entered into International Swap DealersSwaps and Derivatives Association Master Agreements ("ISDA Agreements") with each of our commodity and interest rate derivative counterparties, each of whom is also a lender in our Senior Secured Credit Facility.Facility, which, together with hedge agreements with lenders under such facility, is secured by our oil, NGL and natural gas reserves; therefore, we are not required to post any additional collateral. We do not require collateral from our commodity and interest rate derivative counterparties. The terms of the ISDA Agreements provide the non-defaulting or non-affected party the right to terminate the agreement upon the occurrence of

certain events of default and termination events by a party and also provide for the marking to market of outstanding positions and the offset of the mark to market amounts owed to and by the parties (and in certain cases, the affiliates of the non-defaulting or non-affected party) upon termination.termination; therefore, the credit risk associated with our commodity and interest rate derivative counterparties is somewhat mitigated. We minimize the credit risk in commodity and interest rate derivatives by: (i) limiting our exposure to any single counterparty, (ii) entering into commodity and interest rate derivatives only with counterparties that meet our minimum credit quality standard or have a guarantee from an affiliate that meets our minimum credit quality standard and (iii) monitoring the creditworthiness of our counterparties on an ongoing basis.
ReferWe typically sell production to Note 10a relatively limited number of customers, as is customary in the exploration, development and production business. Our sales of purchased oil are generally made to a few customers. Our joint operations accounts receivable are from a number of oil and natural gas companies, partnerships, individuals and others who own interests in the oil and natural gas properties operated by us.
The majority of our unaudited consolidatedaccounts receivable are unsecured. On occasion we require our customers to post collateral, and the inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial statements included elsewhereresults. In the current market environment, we believe that we could sell our production to numerous purchasers, so that the loss of any one of our major customers would not have a material adverse effect on our financial condition and results of operations solely by reason of such loss. We routinely assess the recoverability of all material trade and other receivables to determine collectability. As the operator of the majority of our wells, we have the ability to realize some or all of our joint operations account receivables through the netting of revenues. Additionally, management believes that any credit risk imposed by a concentration in this Quarterlythe oil and natural gas industry is offset by the creditworthiness of our customer base and industry partners. We routinely assess the recoverability of all material trade and other receivables to determine collectability.
See Notes 2.d and 14 in the 2020 Annual Report for additional disclosures regarding credit risk.discussion of our accounts receivable and revenue recognition, respectively.

Customer performance risk
As a result of multiple factors affecting levels of supply and demand in global oil and gas markets, storage constraints created by excess oil supply in both domestic and international markets and the COVID-19 pandemic have created a risk that our customers will not be able to physically take possession of our oil. In the current market environment, we believe that
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the inability or failure of any one of our major customers to physically take possession of our oil would have an adverse effect on our financial condition and potentially our results of operations.
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Item 4.    Controls and Procedures
Evaluation of disclosure controls and procedures
As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of Laredo's disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act), was performed under the supervision and with the participation of Laredo's management, including our principal executive officer and principal financial officer. Based on that evaluation, these officers concluded that Laredo's disclosure controls and procedures were effective as of September 30, 2017.March 31, 2021. Our disclosure controls and other procedures are designed to provide reasonable assurance that the information required to be disclosed in the reports we file and submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to Laredo's management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

Evaluation of changes in internal control over financial reporting

There were no changes in our internal control over financial reporting during the quarter ended September 30, 2017March 31, 2021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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Part II


Item 1.    Legal Proceedings

From time to time, we are subject to various legal proceedings arising in the ordinary course of business, including proceedings for which we may not have insurance coverage. While many of these matters involve inherent uncertainty except with regard to the specific litigation noted below, as of the date hereof, we do not currently believe that any such legal proceedings will have a material adverse effect on our business, financial position, results of operations or liquidity.

46
On May 3, 2017, Shell filed an Original Petition and Request for Disclosure in the District Court
Table of Harris County, Texas, alleging that the crude oil purchase agreement entered into between Shell and Laredo effective October 1, 2016 does not accurately reflect the compensation to be paid to Shell under certain circumstances due to a drafting mistake. Shell seeks reformation of one clause of the crude oil purchase agreement on the grounds of alleged mutual mistake or, in the alternative, unilateral mistake, an award of the amounts Shell alleges it should have been or should be paid under the agreement, court costs and attorneys’ fees. The Company does not believe there was a drafting mistake made in the crude oil purchase agreement. The Company believes it has substantive defenses and intends to vigorously defend its position. The Company is unable to determine a probability of the outcome of this litigation at this time.Contents
Item 1A.    Risk Factors

In addition to the other information set forth in this Quarterly Report, you should carefully consider the risks discussed in our 20162020 Annual Report. There have been no material changesDepending on the duration of the COVID-19 pandemic and its severity and related economic repercussions, the negative impact of many of the related risks discussed in our risk factors from those described in2020 Annual Report may be heightened or exacerbated. Further, the 2016 Annual Report. The risks described in the 2016 Annual Reportsuch reports are not the only risks facing us. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially and adversely affect our business, financial condition or future results.



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Item 2.    RepurchasePurchases of Equity Securities
The following table summarizes purchases of common stock by Laredo:
Period
Total number of shares purchased(1)
Weighted-average price paid per shareTotal number of shares purchased as
part of publicly announced plans		Maximum value that may yet be purchased under the program as of the respective period-end date
January 1, 2021 - January 31, 2021197 $20.33 — $— 
February 1, 2021 - February 28, 202123,073 $34.35 — $— 
March 1, 2021 - March 31, 202114,394 $34.24 — $— 
Total37,664 — 

(1)Represents shares that were withheld by us to satisfy tax withholding obligations that arose upon the lapse of restrictions on restricted stock awards.

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Period 
Total number of shares withheld(1)
 Average price per share 
Total number of shares purchased as
part of publicly announced plans
 
Maximum number of shares that may
yet be purchased under the plan
July 1, 2017 - July 31, 2017 628
 $10.52
 —
 —
August 1, 2017 - August 31, 2017 2,291
 $12.80
 —
 —
September 1, 2017 - September 30, 2017 411
 $12.70
 —
 —
Total 3,330
      

(1)Represents shares that were withheld by us to satisfy employee tax withholding obligations that arose upon the lapse of restrictions on restricted stock awards.
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Item 3.    Defaults Upon Senior Securities

None.
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Item 4.    Mine Safety Disclosures

The operation of our Howard County, Texas sand mine is subject to regulation by the Federal Mine Safety and Health Administration (the "MSHA") under the Federal Mine Safety and Health Act of 1977 (the "Mine Act"). The MSHA may inspect our Howard County mine and may issue citations and orders when it believes a violation has occurred under the Mine Act. While we contract the mining operations of the Howard County mine to an independent contractor, we may be considered an "operator" for purpose of the Mine Act and may be issued notices or citations if MSHA believes that we are responsible for violations.
Not applicable.The information concerning mine safety violations and other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of the Regulation S-K is included in Exhibit 95.1 to this Quarterly Report.
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Item 5.    Other Information

Not applicable.
Item 7.01. Regulation FD Disclosure.
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Attached as Exhibit 99.1 and incorporated herein by reference are unaudited pro forma condensed consolidated financial statements (the "Pro Forma Financial Statements") that give effect to the Medallion Sale, the repayment
Table of the Senior Secured Credit Facility and the pending redemption of the May 2022 Notes (the"Subsequent Transactions"). We are voluntarily furnishing the Pro Forma Financial Statements, updated from the unaudited pro forma condensed consolidated financial statements included in the Form 8-K filed on October 30, 2017, which were based on prior financial statements, to assist investors in better understanding the impact of the Subsequent Transactions. See Notes 2.h and 16 included elsewhere in this Quarterly Report for additional discussion of the Subsequent Transactions.Contents

Included in the Pro Forma Financial Statements are (i) an unaudited pro forma condensed consolidated balance sheet that has been prepared as if the Subsequent Transactions occurred as of September 30, 2017 and (ii) an unaudited pro forma condensed consolidated statement of operations for the nine months ended September 30, 2017 that has been prepared as if the Subsequent Transactions occurred on January 1, 2017. The Pro Forma Financial Statements furnished herewith are presented for illustrative purposes only and do not purport to represent what our results of operations or financial position would actually have been had the Subsequent Transactions occurred on the dates noted above, or to project our results of operations or financial position for any future periods. The Pro Forma Financial Statements are based on certain assumptions and adjustments described in the notes thereto and should be read together with the historical consolidated financial statements and the related notes included herein and in our 2016 Annual Report.
The information set forth under this Item 5 is intended to be furnished under this Item 5 and also "Item 7.01, Regulation FD Disclosure" of Form 8-K. Such information, including Exhibit 99.1 attached to this Form 10-Q, shall not be deemed "filed" for purposes of Section 18 of the Exchange Act, or otherwise subject to the liabilities of that section, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, as amended, or the Exchange Act, except as shall be expressly set forth by specific reference in such filing.
Disclosure pursuant to Section 13(r) of the Securities Exchange Act of 1934
Pursuant to Section 13(r) of the Exchange Act, we may be required to disclose in our annual and quarterly reports to the SEC, whether we or any of our "affiliates" knowingly engaged in certain activities, transactions or dealings relating to Iran or with certain individuals or entities targeted by United States ("US") economic sanctions. Disclosure is generally required even where the activities, transactions or dealings were conducted in compliance with applicable law. Because the SEC defines the term "affiliate" broadly, it includes any entity under common "control" with us (and the term "control" is also construed broadly by the SEC).
The description of the activities below has been provided to us by Warburg Pincus LLC ("WP"), affiliates of which: (i) beneficially own more than 10% of our outstanding common stock and/or are members of our board of directors, (ii) beneficially own more than 10% of the equity interests of, and have the right to designate members of the board of directors of Santander Asset Management Investment Holdings Limited ("SAMIH"). SAMIH may therefore be deemed to be under common "control" with us; however, this statement is not meant to be an admission that common control exists.
The disclosure below relates solely to activities conducted by SAMIH and its affiliates. The disclosure does not relate to any activities conducted by us or by WP and does not involve our or WP’s management. Neither Laredo nor WP has had any involvement in or control over the disclosed activities, and neither Laredo nor WP has independently verified or participated in the preparation of the disclosure. Neither Laredo nor WP is representing as to the accuracy or completeness of the disclosure nor do we or WP undertake any obligation to correct or update it.
We understand that one or more SEC-reporting affiliates of SAMIH intends to disclose in its next annual or quarterly SEC report that:
(a) Santander UK plc ("Santander UK") holds two savings accounts and one current account for two customers resident in the United Kingdom ("UK") who are currently designated by the US under the Specially Designated Global Terrorist ("SDGT") sanctions program. Revenues and profits generated by Santander UK on these accounts in the nine months ended September 30, 2017 were negligible relative to the overall revenues and profits of Banco Santander SA.
(b) Santander UK holds two frozen current accounts for two UK nationals who are designated by the US under the SDGT sanctions program. The accounts held by each customer have been frozen since their designation and have remained frozen through the nine months ended September 30, 2017. The accounts are in arrears (£1,844.73 in debit combined) and are currently being managed by Santander UK Collections & Recoveries department. No revenues or profits were generated by Santander UK on this account in the nine months ended September 30, 2017.





Item 6.    Exhibits

Exhibit
Number
Description
2.1

Membership Interest Purchase and Sale Agreement, dated as of October 1, 2017, by and among Medallion Midland Acquisition, LLC, Medallion Gathering & Processing, LLC, Laredo Midstream Services, LLC, and Medallion Midstream Holdings, LLC (incorporated by reference to Exhibit 2.1 of Laredo’s Current Report on Form 8-K (File No. 001-35380) filed on October 30, 2017).
3.1

Amended and Restated Certificate of Incorporation of Laredo Petroleum Holdings, Inc. (incorporated by reference to Exhibit 3.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on December 22, 2011).
3.2

Certificate of Ownership and Merger, dated as of December 30, 2013 (incorporated by reference to Exhibit 3.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on January 6, 2014).
3.3

Second Amended and Restated Bylaws of Laredo Petroleum, Inc. (incorporated by reference to Exhibit 3.3 of Laredo's Annual Report on Form 10-K (File No. 001-35380) filed on February 17, 2016).
4.1

Form of Common Stock Certificate (incorporated by reference to Exhibit 4.1 of Laredo's Registration Statement on Form S-1/A (File No. 333-176439) filed on November 14, 2011).
10.1

First Amendment to Fifth Amended and Restated Credit Agreement, dated as of October 24, 2017, among Laredo Petroleum, Inc., as borrower, Wells Fargo Bank, N.A., as administrative agent, Laredo Midstream Services, LLC and Garden City Minerals, LLC, as guarantors, and the banks signatory thereto (incorporated by reference to Exhibit 10.1 of Laredo’s Current Report on Form 8-K (File No. 001-35380) filed on October 30, 2017).
31.1*

Certification of Chief Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
31.2*

Certification of Chief Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
32.1**

Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1**

September 30, 2017 unaudited pro forma condensed consolidated financial information of Laredo Petroleum, Inc., which gives pro forma effect to the following items: (i) the sale of the Company's ownership interests in Medallion, (ii) the repayment of the Company's senior secured credit facility and (iii) the redemption of the May 2022 Notes.
101.INS*
XBRL Instance Document.
101.SCH*
XBRL Schema Document.
101.CAL*
XBRL Calculation Linkbase Document.
101.DEF*
XBRL Definition Linkbase Document.
101.LAB*
XBRL Labels Linkbase Document.
101.PRE*
XBRL Presentation Linkbase Document.
Incorporated by reference (File No. 001-35380, unless otherwise indicated)
Exhibit DescriptionFormExhibitFiling Date
3.1
 8-K3.112/22/2011
3.2
8-K3.16/1/2020
3.3
8-K3.11/6/2014
3.4
8-K3.13/4/2021
4.1
 8-A12B/A4.11/7/2014
10.1
10-K10.182/22/2021
10.2
10-K10.212/22/2021
10.3*
22.1
10-Q22.15/7/2020
31.1*
 
31.2*
 
32.1**
 
95.1*
101 The following financial information from Laredo’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2021, formatted in Inline XBRL: (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Stockholders’ Equity, (iv) Consolidated Statements of Cash Flows and (v) Condensed Notes to the Consolidated Financial Statements.
104Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

*    Filed herewith.
**    Furnished herewith.


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SIGNATURES
 
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. 
LAREDO PETROLEUM, INC.
Date: May 6, 2021By:/s/ Jason Pigott
Jason Pigott
President and Chief Executive Officer
(principal executive officer)
Date: May 6, 2021By:/s/ Bryan J. Lemmerman
Bryan J. Lemmerman
Senior Vice President and Chief Financial Officer
(principal financial officer)
Date: May 6, 2021By:/s/ Jessica R. Wren
Jessica R. Wren
Interim Principal Accounting Officer
(principal accounting officer)
LAREDO PETROLEUM, INC.
Date: November 2, 2017By:/s/ Randy A. Foutch
Randy A. Foutch
Chairman and Chief Executive Officer
(principal executive officer)
Date: November 2, 2017By:/s/ Richard C. Buterbaugh
Richard C. Buterbaugh
Executive Vice President and Chief Financial Officer
(principal financial officer)
Date: November 2, 2017By:/s/ Michael T. Beyer
Michael T. Beyer
Vice President - Controller and Chief Accounting Officer
(principal accounting officer)

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