UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
ýQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 20172022
or
oTRANSITION 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 filerAccelerated 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: 242,512,535November 1, 2022: 16,813,540




LAREDO PETROLEUM, INC.
TABLE OF CONTENTS
Page


ii


Glossary of Oil and Natural Gas Terms
The following terms are used throughout this Quarterly Report on Form 10-Q (this "Quarterly Report"):
"Basin"—A large natural depression on the earth's surface in which sediments, generally brought by water, accumulate.
"Bbl" or "barrel"—One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate, natural gas liquids or water.
"Benchmark Prices"—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, as required by SEC guidelines.
"BOE"—One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil.
"BOE/D"—BOE per day.
"Brent"—A light (low density) and sweet (low sulfur) crude oil sourced from the North Sea, used as a pricing benchmark for ICE oil futures contracts.
"Btu"—British thermal unit, the quantity of heat required to raise the temperature of a one pound mass of water by one degree Fahrenheit.
"Completion"—The process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
"Developed acreage"—The number of acres that are allocated or assignable to productive wells or wells capable of production.
"Dry hole"—A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
"Exchange Act" — The Securities Exchange Act of 1934, as amended.
"Formation"—A layer of rock which has distinct characteristics that differ from nearby rock.
"Fracturing"or"Frac"—The propagation of fractures in a rock layer by a pressurized fluid. This technique is used to release petroleum and natural gas for extraction.
"GAAP"—Generally accepted accounting principles in the United States.
"GCM"—Garden City Minerals, LLC.
"Gross acres" or "gross wells" — The total acres or wells, as the case may be, in which a working interest is owned.
"Henry Hub"—A natural gas pipeline delivery point in south Louisiana that serves as the benchmark natural gas price underlying NYMEX natural gas futures contracts.
"Horizon" — A term used to denote a surface in or of rock, or a distinctive layer of rock that might be represented by a reflection in seismic data.
"Horizontal drilling" — A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.
"ICE"—The Intercontinental Exchange.
"Initial Production"The measurement of production from an oil or gas well when first brought on stream. Often stated in terms of production during the first thirty days.
"Liquids"—Describes oil, condensate and natural gas liquids.
"LMS"—Laredo Midstream Services, LLC.
"MBbl"—One thousand barrels of crude oil, condensate or natural gas liquids.
"MBOE"—One thousand BOE.
"MMBOE"—One million BOE.
iii


"Mcf"—One thousand cubic feet of natural gas.
"MMBtu"—One million Btu.
"MMcf"—One million cubic feet of natural gas.
"Natural gas liquids"or"NGL"—Components of natural gas that are separated from the gas state in the form of liquids, which include propane, butanes and ethane, among others.
"Net acres"—The percentage of gross acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100 acres owns 50 net acres.
"NYMEX"—The New York Mercantile Exchange.
"OPEC"—The Organization of the Petroleum Exporting Countries.
"Productive well"—A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
"Proved reserves"—The estimated quantities of oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.
"Realized Prices"—Prices which reflect adjustments to the Benchmark Prices for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the delivery point without giving effect to our commodity derivative transactions.
"Reservoir"—A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.
"Royalty interest" — An interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any development costs, which may be subject to expiration.
"SEC" — The Securities and Exchange Commission.
"Securities Act" — The Securities Act of 1933, as amended.
"Senior Secured Credit Facility" — The Fifth Amended and Restated Credit Agreement 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.
"Spacing"—The distance between wells producing from the same reservoir.
"Standardized measure"—Discounted future net cash flows estimated by applying Realized Prices to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the oil and natural gas properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.
"Undeveloped acreage"—Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
"Wellhead natural gas"—Natural gas produced at or near the well.
"Working interest" or"WI"—The right granted to the lessee of a property to explore for and to produce and own crude oil, natural gas liquids, natural gas or other minerals. The working interest owners bear the exploration, development and operating costs on either a cash, penalty or carried basis.
"WTI"—West Texas Intermediate grade crude oil. A light (low density) and sweet (low sulfur) crude oil, used as a pricing benchmark for NYMEX oil futures contracts.
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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, and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act").Act. These forward-looking statements include statements, projections and estimates concerning our operations, performance, business strategy, oil, NGLs 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 volatilitypossibility of and substantial decline in, oil, natural gas liquids ("NGL") and natural gas prices, which remain at low levels;
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;
the 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;
capital requirementschanges in domestic and global production, supply and demand for oil, NGL and natural gas, including actions by OPEC members and other oil exporting nations ("OPEC+");
the volatility of oil, NGL and natural gas prices, including in our operationsarea of operation in the Permian Basin;
the potential impact of suspending drilling programs and projects;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 energy, trade and environmental policies and existing and future laws and government regulations;
war and political instability in Ukraine and Russian efforts to destabilize the government of Ukraine and the global hydrocarbon market;
changes in general economic, business or industry conditions, including increases in interest rates, the tightening of the labor market, supply chain disruptions, elevated inflation rates and the possibility of a recession;
the effects, duration, government response or other implications of the coronavirus ("COVID-19") pandemic, or the threat and occurrence of other epidemic or pandemic diseases;
our ability to comply with federal, state and local regulatory requirements;
restrictions on the use of water, including limits on the use of produced water and a moratorium on new produced water well permits recently imposed by the Railroad Commission of Texas, in an effort to control induced seismicity in the Permian Basin;
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 and realize the anticipated benefits of 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 impacting our ability to produce existing wells and/or drill and complete new wells over an extended period of time, including risks related to hydraulic fracturing activities and inclement or extreme weather;
the long-term performance of wells that were completed using different technologies;
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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;
our ability to continue to maintain the borrowing capacity under our Senior Secured Credit Facility (as defined below) 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 for our operations and projects and generate future profits;
our ability to hedge our future production, and regulations that affect our ability to hedge;hedge our future production;
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", "Part II, Item 1A. Risk Factors" and elsewhere in this Quarterly Report, under "Part II, Item 1A. Risk Factors" in our first-quarter 2022 Quarterly Report, and 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, 20162021 (the "2016"2021 Annual Report"), and those set forth from time to time in our other filings with the Securities and Exchange Commission (the "SEC").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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Part I


Item 1.    Consolidated Financial Statements (Unaudited)


Laredo Petroleum, Inc.
Consolidated balance sheets
(in thousands, except share data)
(Unaudited)
September 30, 2022December 31, 2021
Assets  
Current assets:  
Cash and cash equivalents$49,941 $56,798 
Accounts receivable, net162,876 151,807 
Derivatives18,990 4,346 
Other current assets16,254 22,906 
Total current assets248,061 235,857 
Property and equipment: 
Oil and natural gas properties, full cost method: 
Evaluated properties9,465,399 8,968,668 
Unevaluated properties not being depleted115,994 170,033 
Less: accumulated depletion and impairment(7,236,621)(7,019,670)
Oil and natural gas properties, net2,344,772 2,119,031 
Midstream service assets, net90,990 96,528 
Other fixed assets, net40,150 34,590 
Property and equipment, net2,475,912 2,250,149 
Derivatives29,156 32,963 
Other noncurrent assets, net52,796 32,855 
Total assets$2,805,925 $2,551,824 
Liabilities and stockholders' equity 
Current liabilities: 
Accounts payable and accrued liabilities$86,211 $71,386 
Accrued capital expenditures55,729 50,585 
Undistributed revenue and royalties249,295 117,920 
Derivatives58,763 179,809 
Other current liabilities77,275 107,213 
Total current liabilities527,273 526,913 
Long-term debt, net1,181,584 1,425,858 
Derivatives766 — 
Asset retirement obligations70,063 69,057 
Other noncurrent liabilities25,569 16,216 
Total liabilities1,805,255 2,038,044 
Commitments and contingencies
Stockholders' equity:
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued as of September 30, 2022 and December 31, 2021, respectively— — 
Common stock, $0.01 par value, 40,000,000 and 22,500,000 shares authorized, and 16,914,836 and 17,074,516 issued and outstanding as of September 30, 2022 and December 31, 2021, respectively169 171 
Additional paid-in capital2,762,232 2,788,628 
Accumulated deficit(1,761,731)(2,275,019)
Total stockholders' equity1,000,670 513,780 
Total liabilities and stockholders' equity$2,805,925 $2,551,824 
  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 September 30,Nine months ended September 30,
 2022202120222021
Revenues:
Oil sales$311,740 $229,329 $1,069,542 $514,752 
NGL sales59,377 47,949 197,037 133,121 
Natural gas sales73,831 33,998 179,026 98,186 
Midstream service revenues795 1,739 5,030 4,292 
Sales of purchased oil18,371 66,235 106,030 173,500 
Total revenues464,114 379,250 1,556,665 923,851 
Costs and expenses:
Lease operating expenses44,246 29,837 127,136 68,526 
Production and ad valorem taxes29,024 17,937 89,512 45,957 
Transportation and marketing expenses13,285 11,660 39,022 34,477 
Midstream service expenses769 1,014 3,916 2,572 
Costs of purchased oil18,772 68,805 108,516 183,458 
General and administrative11,857 15,008 50,800 49,182 
Organizational restructuring expenses10,420 — 10,420 9,800 
Depletion, depreciation and amortization74,928 62,678 226,555 140,763 
Impairment expense— — — 1,613 
Other operating expense, net1,772 1,798 2,947 4,099 
Total costs and expenses205,073 208,737 658,824 540,447 
Gain on disposal of assets, net4,282 95,201 4,952 93,454 
Operating income263,323 265,714 902,793 476,858 
Non-operating income (expense):
Gain (loss) on derivatives, net100,748 (96,240)(290,995)(467,547)
Interest expense(30,967)(30,406)(96,251)(82,222)
Gain (loss) extinguishment of debt, net553 — (245)— 
Other income, net98 441 433 2,236 
Total non-operating income (expense), net70,432 (126,205)(387,058)(547,533)
Income (loss) before income taxes333,755 139,509 515,735 (70,675)
Income tax benefit (expense):
Current960 (1,300)(4,771)(1,300)
Deferred2,808 (1,377)2,324 707 
Total income tax benefit (expense)3,768 (2,677)(2,447)(593)
Net income (loss)$337,523 $136,832 $513,288 $(71,268)
Net income (loss) per common share:
Basic$20.27 $8.68 $30.64 $(5.29)
Diluted$20.08 $8.56 $30.26 $(5.29)
Weighted-average common shares outstanding:
Basic16,650 15,756 16,750 13,464 
Diluted16,809 15,993 16,963 13,464 
  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

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

Laredo Petroleum, Inc.
Consolidated statement of stockholders' equity
(in thousands)
(Unaudited)
2
  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

The accompanying notes are an integral partTable of this unaudited consolidated financial statement.Contents

Laredo Petroleum, Inc.
Consolidated statements of cash flowsstockholders' equity
(in thousands)
(Unaudited)
Common stockAdditional
paid-in capital
Treasury stock
(at cost)
Accumulated deficit 
 SharesAmountSharesAmountTotal
Balance, June 30, 202217,212 $172 $2,778,538 — $— $(2,099,254)$679,456 
Restricted stock awards— — — — — — 
Restricted stock forfeitures(50)(1)— — — — 
Share repurchases— — — 245 (17,515)— (17,515)
Stock exchanged for tax withholding— — — 11 (853)— (853)
Retirement of treasury stock(256)(2)(18,366)(256)18,368 — — 
Share-settled equity-based compensation— — 2,059 — — — 2,059 
Net income— — — — — 337,523 337,523 
Balance, September 30, 202216,915 $169 $2,762,232 — $— $(1,761,731)$1,000,670 
Common stockAdditional
paid-in capital
Treasury stock
(at cost)
Accumulated deficit
SharesAmountSharesAmountTotal
Balance, June 30, 202113,573 $136 $2,473,709 — $— $(2,628,127)$(154,282)
Restricted stock awards39 — — — — — — 
Restricted stock forfeitures(1)— — — — — — 
Stock exchanged for tax withholding— — — (848)— (848)
Retirement of treasury stock(9)— (848)(9)848 — — 
Exercise of stock options— 173 — — — 173 
Share-settled equity-based compensation— — 2,220 — — — 2,220 
Equity issued for acquisitions of oil and natural gas properties2,507 25 239,942 — — — 239,967 
Net income— — — — — 136,832 136,832 
Balance, September 30, 202116,111 $161 $2,715,196 — $— $(2,491,295)$224,062 
  Nine months ended September 30,
  2017 2016
Cash flows from operating activities:
 

 
Net income (loss)
$140,413

$(242,318)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:





Depletion, depreciation and amortization
113,327

110,813
Impairment expense


162,027
Non-cash stock-based compensation, net of amounts capitalized
26,877

19,562
Mark-to-market on derivatives:





(Gain) loss on derivatives, net
(38,127)
43,783
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)
Amortization of debt issuance costs
3,132

3,231
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)
Other, net
3,445

2,973
(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)
Net cash provided by operating activities 272,051
 245,454
Cash flows from investing activities:





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)
Cash flows from financing activities:





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
Net decrease in cash and cash equivalents
(11,854)
(794)
Cash and cash equivalents, beginning of period
32,672

31,154
Cash and cash equivalents, end of period
$20,818

$30,360

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

3

Table of Contents
Laredo Petroleum, Inc.
Consolidated statements of stockholders' equity
(in thousands)
(Unaudited)
 Common stockAdditional
paid-in capital
Treasury stock
(at cost)
Accumulated deficit 
 SharesAmountSharesAmountTotal
Balance, December 31, 202117,075 $171 $2,788,628 — $— $(2,275,019)$513,780 
Restricted stock awards246 (2)— — — — 
Restricted stock forfeitures(57)(1)— — — — 
Share repurchases— — — 330 (26,586)— (26,586)
Stock exchanged for tax withholding— — — 94 (7,442)— (7,442)
Retirement of treasury stock(424)(4)(34,024)(424)34,028 — — 
Share-settled equity-based compensation— — 7,630 — — — 7,630 
Performance share conversion75 (1)— — — — 
Net income— — — — — 513,288 513,288 
Balance, September 30, 202216,915 $169 $2,762,232 — $— $(1,761,731)$1,000,670 
Common stockAdditional
paid-in capital
Treasury stock
(at cost)
Accumulated deficit
SharesAmountSharesAmountTotal
Balance, December 31, 202012,020 $120 $2,398,464 — $— $(2,420,027)$(21,443)
Restricted stock awards233 (2)— — — — 
Restricted stock forfeitures(42)— — — — — — 
Stock exchanged for tax withholding— — — 53 (2,589)— (2,589)
Retirement of treasury stock(53)— (2,589)(53)2,589 — — 
Exercise of stock options— 173 — — — 173 
Share-settled equity-based compensation— — 6,730 — — — 6,730 
Issuance of common stock, net of costs1,438 14 72,478 — — — 72,492 
Equity issued for acquisitions of oil and natural gas properties2,507 25 239,942 — — — 239,967 
Performance share conversion— — — — — — 
Net loss— — — — — (71,268)(71,268)
Balance, September 30, 202116,111 $161 $2,715,196 — $— $(2,491,295)$224,062 

The accompanying notes are an integral part of these unaudited consolidated financial statements.
4

Table of Contents
Laredo Petroleum, Inc.
Consolidated statements of cash flows
(in thousands)
(Unaudited)
 Nine months ended September 30,
 20222021
Cash flows from operating activities:  
Net income (loss)$513,288 $(71,268)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Share-settled equity-based compensation, net6,295 5,609 
Depletion, depreciation and amortization226,555 140,763 
Impairment expense— 1,613 
Gain on disposal of assets, net(4,952)(93,454)
Mark-to-market on derivatives:
Loss on derivatives, net290,995 467,547 
Settlements paid for matured derivatives, net(423,668)(191,507)
Premiums received for commodity derivatives— 9,041 
Amortization of debt issuance costs4,809 3,608 
Amortization of operating lease right-of-use assets16,523 9,907 
Loss on extinguishment of debt, net245 — 
Deferred income tax benefit(2,324)(707)
Other, net4,600 3,359 
Changes in operating assets and liabilities:
Accounts receivable, net(11,069)(58,681)
Other current assets7,574 (3,026)
Other noncurrent assets, net1,450 (30,285)
Accounts payable and accrued liabilities15,084 21,342 
Undistributed revenue and royalties131,356 56,268 
Other current liabilities(41,362)11,203 
Other noncurrent liabilities(14,697)5,780 
Net cash provided by operating activities720,702 287,112 
Cash flows from investing activities:
Acquisitions of oil and natural gas properties, net(5,581)(627,044)
Capital expenditures:
Oil and natural gas properties(432,124)(278,847)
Midstream service assets(1,163)(2,375)
Other fixed assets(9,101)(3,226)
Proceeds from dispositions of capital assets, net of selling costs2,939 393,742 
Settlements received for contingent consideration1,555 — 
Net cash used in investing activities(443,475)(517,750)
Cash flows from financing activities:
Borrowings on Senior Secured Credit Facility335,000 425,000 
Payments on Senior Secured Credit Facility(400,000)(650,000)
Extinguishment of debt(182,319)— 
Issuance of July 2029 Notes— 400,000 
Proceeds from issuance of common stock, net of offering costs— 72,492 
Share repurchases(26,586)— 
Stock exchanged for tax withholding(7,442)(2,589)
Proceeds from exercise of stock options— 173 
Payments for debt issuance costs(1,725)(14,597)
Other, net(1,012)2,798 
Net cash (used in) provided by financing activities(284,084)233,277 
Net (decrease) increase in cash and cash equivalents(6,857)2,639 
Cash and cash equivalents, beginning of period56,798 48,757 
Cash and cash equivalents, end of period$49,941 $51,396 
 The accompanying notes are an integral part of these unaudited consolidated financial statements.
5

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


Note 1—Organization and basis of presentation
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 one 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—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").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, 20162021 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, 2017,2022, results of operations for the three and nine months ended September 30, 20172022 and 20162021 and cash flows for the nine months ended September 30, 20172022 and 2016.2021. All adjustments are of a recurring nature unless otherwise disclosed herein.
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 20162021 Annual Report.
b.    Reclassifications
Certain previously reported 2022 and 2021 amounts have been reclassified to conform to the current period financial statement presentation. There was no impact on previously reported total assets, total liabilities, net income (loss) or stockholders' equity for the periods presented.
Significant accounting policies
There have been no material changes in the Company's significant accounting policies during the nine months ended September 30, 2022. See Note 2 in the 2021 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 atas of 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 in the unaudited consolidated financial statements2021 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 September 30, 2022. Additionally, the results that may be expected for other interim periods or forCompany did not adopt any new ASUs during the full year.nine months ended September 30, 2022.
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 in an acquisition, (ix) fair value of derivatives and deferred premiums and (x) contingent liabilities. As
6

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


Note 3—Acquisitions and divestitures
fair value is2021 Acquisitions and divestiture
Pioneer Acquisition
On September 17, 2021, the Company entered into a market-based measurement, it is determined based onpurchase and sale agreement (the "Pioneer PSA") with Pioneer Natural Resources USA, Inc ("PXD"), DE Midland III, LLC ("DEM"), Parsley Minerals, LLC ("PM") and Parsley Energy, L.P. ("PE" and collectively with PXD, DEM, and PM, 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 ongoing basis using historical experience and other factors, including"Seller") pursuant to which 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 combinedCompany agreed 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 operationpurchase (the "Pioneer Acquisition"), effective as of July 1, 2021, certain oil and natural gas properties. The majorityproperties in the Midland Basin, including approximately 20,000 net acres, and approximately 135 gross (121 net) operated locations, located in western Glasscock County, Texas, as well as related assets and contracts (the "Pioneer Assets").
On October 18, 2021 ("Pioneer Closing Date"), the Company closed the Pioneer Acquisition for an aggregate purchase price of $210.1 million, comprised of (i) $135.3 million in cash, (ii) 959,691 shares of the Company's accounts receivable are unsecured. Accounts receivable for joint interest billings are recordedcommon stock, par value $0.01 per share (the "common stock"), based upon the share price as amounts billed to customers less an allowance for doubtful accounts.of the Pioneer Closing Date and (iii) $3.9 million in transaction related expenses, inclusive of post-closing adjustments.
The Company maintainsdetermined that the Pioneer Acquisition was 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 afterasset acquisition, as substantially all means of collection have been exhausted and the potential for recovery is remote.
Accounts receivable consisted of the gross assets acquired are concentrated in a group of similar identifiable assets. Accordingly, the consideration paid was allocated to the individual assets acquired and liabilities assumed based on their relative fair values and all transaction costs associated were capitalized.
The following table presents components as of the dates presented:purchase price, inclusive of customary closing adjustments:
(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)(in thousands, except for share and share price data)Accounts receivable for joint operations are presented netAs of an allowance for doubtful accountsOctober 18, 2021
Shares of $0.1 million and $0.2 million asCompany common stock959,691
Company common stock price at the Pioneer Closing Date$73.90 
Value 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.common stock consideration
e.    Derivatives
The Company uses derivatives to reduce exposure to fluctuations in the prices of oil, NGL and natural gas. By removing a significant portion of the price volatility associated with future production, 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 swaps and call spreads.
Derivatives are recorded at fair value and are presented on a net basis on the unaudited consolidated balance sheets as assets and/or liabilities. The Company nets the fair value 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. See Note 8.a for discussion regarding the fair value of the Company's derivatives. 
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.
$70,921 
Cash consideration$135,323 
Transaction costs3,861 
Total purchase price$210,105 
The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed, based on their relative fair values, on the Pioneer Closing Date:
(in thousands)As of October 18, 2021
Evaluated properties$143,021 
Unevaluated properties74,468 
Revenue suspense liabilities assumed(7,384)
Allocated purchase price$210,105 
The Company funded the cash portion of the aggregate purchase price and related transaction costs with respect to the Pioneer Acquisition with cash on hand and borrowings under its Senior Secured Credit Facility.
During the year ended December 31, 2021, in connection with the Pioneer Acquisition, the Company acquired additional interests in the Pioneer Assets through additional sellers that exercised their "tag-along" sales rights, for total cash consideration of $2.9 million, excluding customary purchase price adjustments. These acquisitions were accounted for as asset acquisitions.
Sabalo/Shad Acquisition
On May 7, 2021, the Company entered into two separate purchase and sale agreements, one (the "Sabalo PSA") with Sabalo Energy, LLC and its subsidiary, Sabalo Operating, LLC (collectively, "Sabalo"), and the other (the "Shad PSA" and together with the Sabalo PSA, the "Sabalo/Shad PSAs") with Shad Permian, LLC ("Shad"), to acquire certain Midland Basin oil and natural gas
7

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


properties, including approximately 21,000 net acres and approximately 120 gross (109 net) operated locations and approximately 150 gross (18 net) non-operated locations, located in Howard and Borden Counties, Texas, (collectively, the "Sabalo/Shad Acquisition"). Sabalo and Shad are unaffiliated, but owned interests in the same assets.
f.    Other current assets and liabilities
Other current assets consistedOn July 1, 2021 ("Sabalo/Shad Closing Date"), the Company closed the Sabalo/Shad Acquisition, effective April 1, 2021, for an aggregate purchase price of $863.1 million, comprised of (i) $606.1 million in cash (ii) 2,506,964 shares of the following componentsCompany's common stock, based upon the share price as of the dates presented:Sabalo/Shad Closing Date, and (iii) $17.0 million in transaction related expenses, inclusive of post-closing adjustments.
The Sabalo/Shad Acquisition was accounted for as a single transaction because the Sabalo PSA and Shad PSA were entered into at the same time and in contemplation of one another to form a single transaction designed to achieve an overall economic effect. The Company determined that the Sabalo/Shad Acquisition was an asset acquisition, as substantially all of the gross assets acquired are concentrated in a group of similar identifiable assets. Accordingly, the consideration paid was allocated to the individual assets acquired and liabilities assumed based on their relative fair values and all transaction costs associated were capitalized.
(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
The following table presents components of the purchase price, inclusive of customary closing adjustments:

(1)(in thousands, except for share and share price data)See Note 2.i for discussionAs of inventory held byJuly 1, 2021
Shares of Company common stock2,506,964
Company common stock price at the Company.Sabalo/Shad Closing Date$95.72 
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.    Property and equipment
The following table sets forth the Company's property and equipment as of the dates presented:
(in thousands) September 30, 2017 December 31, 2016
Evaluated oil and natural gas properties $5,863,536
 $5,488,756
Less accumulated depletion and impairment (4,616,246) (4,514,183)
Evaluated oil and natural gas properties, net 1,247,290
 974,573
     
Unevaluated properties not being depleted 211,720
 221,281
     
Midstream service assets 161,144
 150,629
Less accumulated depreciation and impairment (30,737) (24,389)
Midstream service assets, net 130,407
 126,240
     
Depreciable other fixed assets 50,767
 52,491
Less accumulated depreciation and amortization (23,779) (22,632)
Depreciable other fixed assets, net 26,988
 29,859
     
Land 14,914
 14,914
     
Total property and equipment, net $1,631,319
 $1,366,867
For the three months ended September 30, 2017 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.
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 employee costs, incurred for the purpose of exploring for or developing oil and natural gas properties, are capitalized and depleted on a composite unit of production method based on proved oil, NGL and natural gas reserves. Such amounts 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 employee costs, associated with production and general corporate activities are expensed in the period incurred. Sales of oil and natural gas
Value of Company common stock consideration$239,967 
Cash consideration$606,126 
Transaction costs17,020 
Total purchase price$863,113 
The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed, based on their relative fair values, on the Sabalo/Shad Closing Date:
(in thousands)As of July 1, 2021
Evaluated properties$503,005 
Unevaluated properties362,977 
Revenue suspense liabilities assumed(4,269)
Inventory1,400 
Allocated purchase price$863,113 
The Company funded the cash portion of the aggregate purchase price and related transaction costs with respect to the Sabalo/Shad Acquisition with proceeds from borrowings under its Senior Secured Credit Facility and the Working Interest Sale described below.
Working Interest Sale
On May 7, 2021, the Company entered into a purchase and sale agreement (the "Sixth Street PSA") with Piper Investments Holdings, LLC, an affiliate of Sixth Street Partners, LLC ("Sixth Street"), to sell 37.5% of the Company's working interest in certain producing wellbores and the related properties primarily located within Glasscock and Reagan Counties, Texas, subject to certain excluded assets and title diligence procedures (the "Working Interest Sale").
On July 1, 2021 (the "Sixth Street Closing Date"), the Company closed the Working Interest Sale for cash proceeds of $405.0 million. In addition to such proceeds, the Sixth Street PSA also provided the Company with the right to receive up to a maximum of $93.7 million in additional cash consideration if certain cash flow targets related to divested oil and natural gas property operations are met ("Sixth Street Contingent Consideration"). The Sixth Street Contingent Consideration is made up of quarterly payments through June 2027 totaling up to $38.7 million and a potential balloon payment of $55.0 million in June 2027. On the Sixth Street Closing Date, the fair value of the Sixth Street Contingent Consideration was determined to be $33.8 million. The Sixth Street Contingent Consideration is accounted for as a contingent consideration derivative, with all
8

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 costsgains 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 the costs directly associated with acquisition and evaluation of unevaluated properties 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 is 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 evaluated 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.
The full cost ceiling is based principally on the estimated future net revenues from proved oil and natural gas properties 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, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead ("Realized Prices"). The Realized Prices are utilized to calculate the discounted future net revenues in the full cost ceiling calculation.
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 expense in the period such excess occurs. Once incurred, a write-down of oil and natural gas properties is not reversible.
Full cost ceiling impairment expense for 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 during 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.
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.
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)


On October 30, 2017, LMS, together with the third-party 51% interest holder, completed the previously announced sale of 100% 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 of 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.
i. Long-lived assets and inventory
Impairment losses are recorded on property and equipment used in operations and other long-lived assets when indicators of 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, 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" 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 commitmentfair value of the Senior Secured Credit Facility, which is includedcontingent consideration derivative recognized 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.
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 liabilityearnings in the period in which they are incurredthe changes occur. See Notes 8 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:
(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 cash 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.
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 59 for further discussion regardingof the restricted stock awards, stock option awards, performance share awards and performance unit awards.Sixth Street Contingent Consideration.
o.    July 2016 and May 2016 Equity Offerings
On July 19, 2016,Subsequent to the Sixth Street Closing Date, 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, commissionscontinues to own 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 expensedoperate its remaining working interest in the period incurred. Liabilities for expendituresproperties sold to Sixth Street; however, the results 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.
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 propertiesrelated to the 37.5% working interests sold were eliminated from the ongoing operations of the Company, and the Company has no continuing involvement in the properties.Company's financial statements. This divestiture doesdid not represent a strategic shift and will not have a major effect on the Company's future 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 underPursuant to the acquisition method of accounting. Accordingly,rules governing full cost accounting, the Company conducts assessmentsrecorded a gain on the Working Interest Sale of $94.3 million, net assets acquiredof transaction expenses of $11.6 million, on the Company's consolidated statements of operations, inclusive of post-closing adjustments, as this divestment represented more than 25% of the Company's June 30, 2021 proved reserves. For the purposes of calculating the gain, total capitalized costs were allocated between reserves sold 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 pricesreserves retained as of the closingSixth Street Closing Date.
Note 4—Debt
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 adjusted for transportationpresented:
 September 30, 2022December 31, 2021
(in thousands)Long-term debtDebt issuance costs, netLong-term debt, netLong-term debtDebt issuance costs, netLong-term debt, net
January 2025 Notes$529,464 $(4,355)$525,109 $577,913 $(6,345)$571,568 
January 2028 Notes326,756 (3,978)322,778 361,044 (5,024)356,020 
July 2029 Notes298,214 (4,517)293,697 400,000 (6,730)393,270 
Senior Secured Credit Facility(1)
40,000 — 40,000 105,000 — 105,000 
Total$1,194,434 $(12,850)$1,181,584 $1,443,957 $(18,099)$1,425,858 

(1)Debt issuance costs, net related to the Senior Secured Credit Facility of $7.8 million and regional price differentials; (iii) forecasted ad valorem taxes, production taxes, income taxes, general$8.1 million as of September 30, 2022 and administrative expenses, operating expensesDecember 31, 2021, respectively, are included in "Other noncurrent assets, net" on the unaudited consolidated balance sheets.
Senior unsecured notes repurchases
The following table presents the Company's repurchases of its senior unsecured notes and development costs; and (iv) a peer group weighted-average costthe related gain or loss on extinguishment of capital rate subject to additional project-specific risk factors. To compensatedebt during the periods presented:
(in thousands)Three months ended September 30, 2022Nine months ended September 30, 2022
January 2025 Notes$48,449 $48,449 
January 2028 Notes28,038 34,288 
January 2029 Notes76,010 101,786 
Total principal amount repurchased$152,497 $184,523 
 
Write off of debt issuance costs$(1,958)$(2,449)
Difference between consideration paid and net carrying amounts2,511 2,204 
Gain (loss) on extinguishment of debt, net$553 $(245)
See Note 15 for the inherent riskCompany's additional repurchases 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 satisfiedits senior unsecured notes subsequent to September 30, 2016.2022.
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:

9
(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

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


Senior Secured Credit Facility
c. Exchange of unevaluated oil and natural gas properties
From time to time,On August 30, 2022, the Company exchanges undeveloped acreage with third parties, with no gain or loss recognized pursuantentered into the Ninth Amendment to the rules governing full cost accounting.
Note 4—Debt
a.   March 2023 Notes
On March 18, 2015, the Company completed an offering of $350.0 million in aggregate principal amount of 6 1/4% senior unsecured notes due 2023 (the "March 2023 Notes"). The March 2023 Notes will mature on March 15, 2023 and bear an interest rate of 6 1/4% per annum, payable semi-annually, in cash in arrears on March 15 and September 15 of each year, commencing September 15, 2015. The March 2023 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 "Ninth Amendment"). The March 2023 Notes are callable by the Company beginning March 15, 2018 at a price of 104.688% of face value with call premiums declining annuallyNinth Amendment, among other things, added additional capacity to 100% of face value on March 15, 2021 and thereafter.
b.    January 2022 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 will mature on January 15, 2022 and bear 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 are fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certainmaking repurchases of the Company's future restricted subsidiaries, subjectcommon stock and clarified the conditions 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, the Company completed an offering of $500.0 million in aggregate principal amount of 7 3/8% senior unsecured notes due 2022 (the "May 2022 Notes"). The May 2022 Notes will mature on May 1, 2022 and bear an interest rate of 7 3/8% per annum, payable semi-annually, in cash in arrears on May 1 and November 1 of each year, commencing November 1, 2012. The May 2022 Notes are fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certainmaking redemptions of the Company's future restricted subsidiaries, subject to certain Releases. The May 2022 Notes became callable by the Company on May 1, 2017 at a price of 103.688% of face value with call premiums declining annually to 100% of face value on May 1, 2020 and thereafter.debt.
See Note 16.c for discussion regarding the commencement of a redemption of the outstanding $500.0 million in aggregate principal amount of the May 2022 Notes subsequent to September 30, 2017.
d.    Senior Secured Credit Facility
As of September 30, 2017,2022, the Senior Secured Credit Facility, which matures on July 16, 2025 (subject to a springing maturity date of July 29, 2024 if any of the January 2025 Notes are outstanding on such date), had a maximum credit amount of $2.0 billion, a borrowing base and an aggregate elected commitment each of $1.25 billion and $1.0 billion, respectively, with $155.0a $40.0 million balance outstanding, and was subject to an interest rate of 3.25%5.379%. 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 $20.0and $80.0 million. As of December 31, 2021, the Company had a $44.1 million. letter of credit outstanding under the Senior Secured Credit Facility. No letters of credit were outstanding under the Senior Secured Credit Facility as of September 30, 2017 or 2016.2022. For additional information see Note 7 in the 2021 Annual Report. See Note 16.b15 for discussion of (i) additional borrowingsrepayments on and (ii) an increase in the repaymentborrowing base of the Senior Secured Credit Facility subsequent to September 30, 2017.2022.
Note 5—Stockholders' equity
Authorized shares increase
On May 26, 2022, upon recommendation of the Company's board of directors, stockholders approved an amendment to the Company's Amended and Restated Certificate of Incorporation to increase the number of authorized shares of its common stock from 22,500,000 shares to 40,000,000 shares.
Share repurchase program
On May 31, 2022, the Company's board of directors authorized a $200.0 million share repurchase program. The repurchase program commenced in May 2022 and expires in May 2024. Share repurchases under the program may be made through a variety of methods, which may include open market purchases, including under plans complying with Rule 10b5-1 of the Exchange Act, and privately negotiated transactions. The timing and actual number of share repurchases will depend upon several factors, including market conditions, business conditions, the trading price of the Company's common stock and the nature of other investment opportunities available to the Company.
The following table presents the Company's open market repurchases of its common stock during the periods presented:
(in thousands, except for share and share price data)Three months ended September 30, 2022Nine months ended September 30, 2022
Shares of Company common stock repurchased244,687329,848
Average share price(1)
$71.58 $80.60 
Total$17,515 $26,586 
______________________________________________________________________________
(1)Average share price includes any commissions paid to repurchase stock.
All shares were retired upon repurchase. See Note 15 for the Company's additional repurchases of its common stock subsequent to September 30, 2022.
ATM Program
On 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 having an aggregate gross sales price of up to $75.0 million through an "at-the-market" equity program (the "ATM Program").
During the nine months ended September 30, 2021, the Company sold 1,438,105 shares of its common stock pursuant to the ATM Program for net proceeds of approximately $72.5 million, after underwriting commissions and other related expenses,
10

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


On October 20, 2017, pursuantthus completing the ATM Program. Proceeds from the share sales were utilized to a regular semi-annual redetermination, the lenders reaffirmed the $1.0 billion borrowing base underreduce borrowings on the Senior Secured Credit Facility.
Note 6—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, performance unit awards, phantom unit awards and other awards. On May 20, 2021, the Company's stockholders approved an amendment to the Equity Incentive Plan to, among other things, increase the maximum number of shares of the Company's common stock issuable under the Equity Incentive Plan from 1,492,500 to 2,432,500 shares.
See Note 9 in the 2021 Annual Report for additional discussion of the Company's equity-based compensation awards.
The following table presents activity for equity-based compensation awards for the nine months ended September 30, 2022:
Equity AwardsLiability Awards
(in thousands)Restricted Stock AwardsStock Option Awards
Performance Share Awards(1)(2)
Performance Unit Awards
Phantom Unit Awards(3)
Outstanding as of December 31, 2021350 72 209 33 
Granted246 — 62 — — 
Forfeited(57)— (16)(59)— 
Vested(180)— (70)— (15)
Expired or canceled— (2)— — — 
Outstanding as of September 30, 2022359 48 150 18 
_____________________________________________________________________________
(1)The performance share awards granted on February 28, 2019 had a performance period of January 1, 2019 to December 31, 2021 and, as their market and performance criteria were satisfied, resulted in a 107% payout. As such, the granted awards vested and were converted into 75,107 shares of the Company's common stock during the nine months ended September 30, 2022 based on this 107% payout.
(2)On February 22, 2022, the Company granted performance share awards with a performance period of January 1, 2022 through December 31, 2024. The market criteria consists of: (i) annual relative total shareholder return comparing the Company's shareholder return to the shareholder return of the exploration and production companies listed in the Russell 2000 Index and (ii) annual absolute total shareholder return. The performance criteria for these awards consists of: (i) earnings before interest, taxes, depreciation, amortization and exploration expense and three-year total debt reduction, (ii) growth in inventory and (iii) emissions reduction targets. Any shares earned are expected to be paid in equity during the first quarter following the completion of the requisite service period, based on the achievement of market and performance criteria, and the payout can range from 0% to 225%.
(3)On March 1, 2022 and March 5, 2022, the vested phantom unit awards were settled and paid out in cash at a fair value of $76.60 and $83.00 based on the Company's closing stock price on the respective vesting dates.
As of September 30, 2022, total unrecognized cost related to equity-based compensation awards was $23.2 million, of which $5.3 million was attributable to liability awards which will be settled in cash rather than shares. Such cost will be recognized on a straight-line basis over an expected weighted-average period of 1.99 years.
11

Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
Equity-based compensation
The following table reflects equity-based compensation expense for the periods presented:
Three months ended September 30,Nine months ended September 30,
(in thousands)2022202120222021
Equity awards:
Restricted stock awards$1,818 $1,810 $6,428 $5,630 
Performance share awards241 410 1,202 1,093 
Stock option awards— — — 
Total share-settled equity-based compensation, gross$2,059 $2,220 $7,630 $6,730 
Less amounts capitalized(421)(409)(1,335)(1,121)
Total share-settled equity-based compensation, net$1,638 $1,811 $6,295 $5,609 
Liability awards:
Performance unit awards$(4,311)$1,380 $1,595 $8,552 
Phantom unit awards199 269 1,078 1,202 
Total cash-settled equity-based compensation, gross$(4,112)$1,649 $2,673 $9,754 
Less amounts capitalized(45)(60)(247)(353)
Total cash-settled equity-based compensation, net$(4,157)$1,589 $2,426 $9,401 
Total equity-based compensation, net$(2,519)$3,400 $8,721 $15,010 
Note 7—Net income (loss) per common share
Basic and diluted net income (loss) per common share are computed by dividing net income (loss) by the weighted-average 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 and non-vested performance share awards. See Note 9 in the 2021 Annual Report for additional discussion of these awards. For the nine months ended September 30, 2021, all of these awards 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 following table reflects the calculations 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)2022202120222021
Net income (loss) (numerator)$337,523 $136,832 $513,288 $(71,268)
Weighted-average common shares outstanding (denominator):
Basic16,650 15,756 16,750 13,464 
Dilutive non-vested restricted stock awards159 187 197 — 
Dilutive non-vested performance share awards(1)
— 50 16 — 
Diluted16,809 15,993 16,963 13,464 
Net income (loss) per common share:
Basic$20.27 $8.68 $30.64 $(5.29)
Diluted$20.08 $8.56 $30.26 $(5.29)
_____________________________________________________________________________
(1)The dilutive effect of the non-vested performance shares for the three and nine months ended September 30, 2022 was calculated assuming the performance period ended on September 30, 2022.
12

Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
Note 8—Derivatives
The Company has two types of derivative instruments as of September 30, 2022: (i) commodity derivatives and (ii) a contingent consideration derivative. In previous periods, the Company also engaged in an interest rate swap derivative, which concluded during the quarterly period ended June 30, 2022. See (i) Note 2 in the 2021 Annual Report for discussion of the Company's significant accounting policies for derivatives and presentation and (ii) Note 9 for discussion of fair value measurement of derivatives on a recurring basis. The Company's aggregate elected commitmentderivatives 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 $1.0 billion remained unchanged.operations.
The following table summarizes components of the Company's gain (loss) on derivatives, net by type of derivative instrument for the periods presented:
e.    
Three months ended September 30,Nine months ended September 30,
(in thousands)2022202120222021
Commodity$110,356 $(101,394)$(285,715)$(472,296)
Interest rate— (17)14 (43)
Contingent consideration(9,608)5,171 (5,294)4,792 
Gain (loss) on derivatives, net$100,748 $(96,240)$(290,995)$(467,547)
Commodity
Due to the inherent volatility in oil, NGL and natural gas prices and the sometimes wide pricing differentials 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 10 in the 2021 Annual Report for discussion of transaction types and settlement indexes. During the nine months ended September 30, 2022, the Company’s derivatives were settled based on reported prices on commodity exchanges, with (i) oil derivatives settled based on WTI NYMEX and 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.

13

Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
The following table summarizes open commodity derivative positions as of September 30, 2022, for commodity derivatives that were entered into through September 30, 2022, for the settlement periods presented:
 Remaining Year 2022Year 2023
Oil: 
WTI NYMEX - Swaps:
Volume (Bbl)92,000 — 
Weighted-average price ($/Bbl)$64.40 $— 
WTI NYMEX - Collars:
Volume (Bbl)1,407,600 4,362,000 
Weighted-average floor price ($/Bbl)$72.65 $67.93 
Weighted-average ceiling price ($/Bbl)$86.54 $82.89 
Brent ICE - Swaps:
Volume (Bbl)1,039,600 — 
Weighted-average price ($/Bbl)$48.34 $— 
Brent ICE - Collars: 
Volume (Bbl)391,000 — 
Weighted-average floor price ($/Bbl)$56.65 $— 
Weighted-average ceiling price ($/Bbl)$65.44 $— 
NGL:
Purity Ethane - Swaps:
Volume (Bbl)386,400 — 
Weighted-average price ($/Bbl)$11.42 $— 
Non-TET Propane - Swaps:
Volume (Bbl)294,400 — 
Weighted-average price ($/Bbl)$35.91 $— 
Non-TET Normal Butane - Swaps:
Volume (Bbl)92,000 — 
Weighted-average price ($/Bbl)$41.58 $— 
Non-TET Isobutane - Swaps:
Volume (Bbl)27,600 — 
Weighted-average price ($/Bbl)$42.00 $— 
Non-TET Natural Gasoline - Swaps:
Volume (Bbl)92,000 — 
Weighted-average price ($/Bbl)$60.65 $— 
Natural gas:
Henry Hub NYMEX - Swaps: 
Volume (MMBtu)920,000 — 
Weighted-average price ($/MMBtu)$2.73 $— 
Henry Hub NYMEX - Collars: 
Volume (MMBtu)7,360,000 25,550,000 
Weighted-average floor price ($/MMBtu)$3.09 $4.14 
Weighted-average ceiling price ($/MMBtu)$3.84 $8.43 
Waha Inside FERC to Henry Hub NYMEX - Basis Swaps: 
Volume (MMBtu)7,314,000 25,550,000 
Weighted-average differential ($/MMBtu)$(0.36)$(1.65)
14

Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
Contingent consideration
The Sixth Street PSA provides for potential contingent payments to be paid to the Company if certain cash flow targets are met related to divested oil and natural gas property operations. The Sixth Street Contingent Consideration provides the Company with the right to receive up to a maximum of $93.7 million in additional cash consideration, comprised of potential quarterly payments through June 2027 totaling up to $38.7 million and a potential balloon payment of $55.0 million in June 2027. As of September 30, 2022, the maximum remaining additional cash consideration of the contingent consideration was $90.1 million. The fair value of the Sixth Street Contingent Consideration was $35.9 million as of December 31, 2021 and $28.7 million as of September 30, 2022. See Note 3 for further discussion of the Working Interest Sale associated with the Sixth Street Contingent Consideration.
At each quarterly reporting period, the Company remeasures contingent consideration with the change in fair value recognized in "Gain (loss) on derivatives, net" under "Non-operating income (expense)" on the unaudited consolidated statements of operations.
Note 9—Fair value measurements
See the beginning of debtNote 11 in the 2021 Annual Report for information about the fair value hierarchy levels.
Fair value measurement on a recurring basis
See Note 8 for further discussion of the Company's derivatives, and see Note 2 in the 2021 Annual Report for the Company's significant accounting policies for derivatives.

15

Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
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:
September 30, 2022
(in thousands)Level 1Level 2Level 3Total gross fair valueAmounts offsetNet fair value presented on the unaudited consolidated balance sheets
Assets:
Current:
Commodity$— $49,566 $— $49,566 $(34,716)$14,850 
Contingent consideration— — 4,140 4,140 — 4,140 
Noncurrent:
Commodity— 5,204 — 5,204 (598)4,606 
Contingent consideration— — 24,550 24,550 — 24,550 
Liabilities:
Current:
Commodity— (93,479)— (93,479)34,716 (58,763)
Noncurrent:
Commodity— (1,364)— (1,364)598 (766)
Net derivative liability positions$— $(40,073)$28,690 $(11,383)$— $(11,383)
December 31, 2021
(in thousands)Level 1Level 2Level 3Total gross fair valueAmounts offsetNet fair value presented on the
consolidated balance sheets
Assets:
Current:
Commodity$— $21,671 $— $21,671 $(21,671)$— 
Contingent consideration— — 4,346 4,346 — 4,346 
Noncurrent:
Commodity— 1,448 — 1,448 — 1,448 
Contingent consideration— — 31,515 31,515 — 31,515 
Liabilities:
Current:
Commodity— (201,428)— (201,428)21,671 (179,757)
Interest rate— (52)— (52)— (52)
Noncurrent:
Commodity— — — — — — 
Net derivative liability positions$— $(178,361)$35,861 $(142,500)$— $(142,500)
See Note 11 in the 2021 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 Sixth Street Contingent Consideration associated with the Working Interest Sale was categorized as Level 3 of the fair value hierarchy, as the Company utilized its own cash flow projections along with a risk-adjusted discount rate generated by a third-party valuation specialist to determine the valuation. The Company reviewed the third-party specialist's valuation,
16

Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)
including the related inputs, and analyzed changes in fair values between the Sixth Street Closing Date and the reporting dates. The fair value of the Sixth Street Contingent Consideration was recorded as part of the basis in the oil and natural gas properties divested and as a contingent consideration asset. At each quarterly reporting period prior to the end of the contingency period, the Company will remeasure the Sixth Street Contingent Consideration with the changes in fair value recognized in the earnings for such quarter. See Note 3 for further discussion of the Working Interest Sale associated with the Sixth Street Contingent Consideration.
The following table summarizes the changes in contingent consideration derivatives classified as Level 3 measurements for the periods presented:
Three months ended September 30,Nine months ended September 30,
(in thousands)2022202120222021
Balance of Level 3 at beginning of period$38,620 $— $35,861 $— 
Sixth Street Contingent Consideration valuation as of Sixth Street Closing Date— 33,832 — 33,832 
Change in Sixth Street Contingent Consideration fair value(9,608)5,182 (5,294)5,182 
Settlements realized(1)
(322)— (1,877)— 
Balance of Level 3 at end of period$28,690 $39,014 $28,690 $39,014 
_____________________________________________________________________________
(1)For the nine months ended September 30, 2022, $1.6 million of realized settlements has been received and is included in "Settlements received for contingent consideration" in cash flows from investing activities on the unaudited consolidated statements of cash flows, and $0.3 million is a receivable at period end.
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 September 30, 2022December 31, 2021
(in thousands) Long-term
debt
 
Fair
value
 Long-term
debt
 
Fair
value
(in thousands)Carrying
amount
Fair
value(1)
Carrying
amount
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$529,464 $525,059 $577,913 $589,471 
January 2028 NotesJanuary 2028 Notes326,756 313,686 361,044 378,578 
July 2029 NotesJuly 2029 Notes298,214 274,771 400,000 390,000 
Senior Secured Credit Facility 155,000
 155,035
 70,000
 69,975
Senior Secured Credit Facility40,000 39,959 105,000 105,040 
Total $1,455,000
 $1,496,112
 $1,370,000
 $1,413,419
Total$1,194,434 $1,153,475 $1,443,957 $1,463,089 

(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 Level 2 fair value hierarchy quoted market prices for each respective instrument as of September 30, 20172022 and December 31, 2016 quoted market price (Level 1) for each respective instrument.2021. The fair values of the outstanding debt onunder the Senior Secured Credit Facility was estimated utilizing the Level 2 fair value hierarchy pricing model for similar instruments as of September 30, 20172022 and December 31, 2016 were estimated utilizing pricing models for similar instruments (Level 2). See Note 8 for information about fair value hierarchy levels.2021.
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 compensation10—Commitments and contingencies
TheFrom time to time, the Company has a Long-Term Incentive Plan (the "LTIP"), which provides for the granting of incentive awardsis subject to various legal proceedings arising in the formordinary course of restricted stock awards, stock option awards, performance share awards, performance unit awardsbusiness, including those that arise from interpretation of federal, state and other awards. The LTIP provides forlocal laws and regulations affecting 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 additionindustry, personal injury claims, title disputes, royalty disputes, contract claims, contamination claims relating to "Oiloil and natural gas properties"exploration and development and environmental claims, including claims involving assets previously sold to third parties and no longer part of the Company's current operations. The Company may not have insurance coverage for some of these proceedings and failure to comply with applicable laws and regulations can result in the unaudited consolidated balance sheets.substantial penalties. While many of
17

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


a.    Restricted stock awards
All service vesting restricted stock awards are treatedthese matters involve inherent uncertainty, 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
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.    
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.
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,hereof, 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.
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.
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.
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
 $
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.
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
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.
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
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—Net income (loss) per common share
Basic net income (loss) per common share is 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 performance share awards, non-vested restricted stock awards and outstanding stock option awards. For the nine months ended September 30, 2016, all of these potentially dilutive items 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 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 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.
The following is the calculation of basic and diluted weighted-average common shares outstanding and 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)

(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—Commitments and contingencies
a.    Litigation
From time to time the Company is involved in legal proceedings, and/or may be subject to industry rulings that could bring rise to claims in the ordinary course of business. In the case of a known contingency, the Company accrues a liability when the loss is probable and the amount is reasonably estimable. Except with regard to the specific litigation noted below, the Company has concluded that the likelihood is remote that the ultimate resolution of any such pending litigation or pending claimsif ultimately decided adversely, will be material ornot 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 See Note 15 in the District Court2021 Annual Report for further discussion of Harris County, Texas, alleging that the crude oil purchase agreement entered into between Shelllitigation 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 costsenvironmental 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 defensesfederal, state and intends to vigorously defend its position. The Company is unable 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. The Company has accounted for the costs (and resulting increased crude oil price realization) as reflected in the terms of the crude oil purchase agreement.local regulations.
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 and contain an early termination clause that requires the Company to potentially pay a penalty to the third party should the Company cease drilling efforts. This penalty would negatively impact the Company's financial statements upon early contract termination. There were no penalties incurred for early contract termination for either of the nine months ended September 30, 2017 or 2016. The future commitment of $3.0 million as of September 30, 2017 is not recorded in the accompanying unaudited consolidated balance sheets. Management does not currently anticipate the early termination of this contract in 2017.

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$7.7 million and $1.1$2.8 million during the three and nine months ended September 30, 2017,2022 and 2021, respectively, and $1.6 million during the three and nine months ended September 30, 2016, which are reportedrecorded in "Transportation and marketing expenses" on the unaudited consolidated statements of operationsoperations. The Company's estimated aggregate liability of firm transportation payments on excess capacity is $8.6 million as of September 30, 2022, and is included in "Accounts payable and accrued liabilities" on the unaudited consolidated balance sheet. As of September 30, 2022, future firm sale and transportation commitments of $171.5 million are expected to be satisfied and, as such, are not recorded as a liability on the unaudited consolidated balance sheet.
Note 11—Supplemental cash flow and non-cash information
The following table presents supplemental cash flow and non-cash information for the periods presented:
Nine months ended September 30,
(in thousands)20222021
Supplemental cash flow information:
Cash paid for interest, net of $3,265 and $3,081 of capitalized interest, respectively$130,082 $95,684 
Supplemental non-cash operating information:
Right-of-use assets obtained in exchange for operating lease liabilities(1)
$34,532 $7,532 
Supplemental non-cash investing information:
Fair value of contingent consideration asset on transaction date(2)
$— $33,832 
Change in accrued capital expenditures$5,144 $25,380 
_____________________________________________________________________________
(1)See Note 5 in the "Other2021 Annual Report for additional discussion of the Company's leases.
(2)See Note 3 for discussion of the Company's 2021 Working Interest Sale which included contingent consideration. See Note 9 for discussion of the quarterly remeasurement of this contingent consideration.
Note 12—Income taxes
The Company is subject to federal and state income taxes and the Texas franchise tax. As of September 30, 2022, the Company had federal net operating loss ("NOL") carryforwards totaling $1.6 billion, $1.2 billion of which will begin to expire in 2031 and $366.8 million of which will not expire but may be limited in future periods, and state of Oklahoma net operating loss carryforwards totaling $34.4 million that will begin to expire in 2032. If the Company were to experience an "ownership change" as determined under Section 382 of the Internal Revenue Code, the Company's ability to offset taxable income arising after the ownership change with net operating losses arising prior to the ownership change would be limited. As of September 30, 2022, no such ownership change has occurred.
As of September 30, 2022, 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 September 30, 2022 and the Company's ability to capitalize intangible drilling costs, rather than expensing these costs and future projections of taxable income. A significant item of objective negative evidence
18

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


considered was the cumulative historical three-year pre-tax loss and net deferred tax asset position. Such objective evidence limits the ability to consider other subjective evidence such as the Company’s potential for future growth.
expenses" line item. Future commitments of $369.4 million asAs of September 30, 2017 are not2022, a total valuation allowance of $325.7 million has been recorded into offset the accompanying unaudited consolidated balance sheets. For information regarding the TA related to Medallion, see Note 2.h.
d.    Federal and state regulations

Oil and natural gas exploration, production and related operations are subject to extensiveCompany's federal and state laws, rules and regulations. Failure to comply with these laws, rules and regulations can resultOklahoma net deferred tax assets, resulting 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 ita $1.5 million Texas net deferred asset, which 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 "Other noncurrent assets, net" on the unaudited consolidated balance sheets relatedsheets.
Since September 30, 2015, the Company has recorded a full valuation allowance against its federal and Oklahoma net deferred tax position. As such, the Company's effective tax rate is 1%, due to Medallionthe Texas franchise tax. The Company's effective tax rate is affected by changes in valuation allowances, recurring permanent differences and discrete items that may occur in any given year, but are not consistent from year to year. For the three and nine months ended September 30, 2022 and 2021, the Company’s items of discrete income tax expense or benefit were not material.
On August 16, 2022, the U.S. Inflation Reduction Act of 2022 (the "IRA") was signed into U.S. law. The IRA includes various tax provisions, including a 1% excise tax on stock repurchases made by publicly traded U.S. corporations, expanded tax credits for clean energy incentives and a 15% corporate alternative minimum tax that applies to certain corporations with adjusted financial statement income in excess of $1.0 billion. The Company is evaluating the IRA and its requirements, as well as the potential impact of the dates presented:IRA to its business.
Note 13—Related parties
(in thousands) December 31, 2016
Accrued capital expenditures $586
Other current liabilities $118
Halliburton
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 discussionChairman of the TA between LMS and a wholly-owned subsidiaryCompany's board 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.Halliburton Company ("Halliburton"). Halliburton provides drilling and completions services to the Company.
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 summarizespresents 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 Archrockoil and natural gas properties paid to Halliburton included in the unaudited consolidated statements of cash flows totaled a de minimis amount. No such amounts were included for the nine month endsperiods presented:
 Nine months ended September 30,
(in thousands)20222021
Capital expenditures for oil and natural gas properties$78,749 $42,074 
Note 14—Organizational restructurings
On August 24, 2022, the Company announced the departure of the Company's Senior Vice President and Chief Operating Officer. In connection with the departure, the Company incurred one-time charges for certain payments and benefits of $10.4 million during the three months ended September 30, 2017.     2022. These charges were recorded as "Organizational restructuring expenses" on the unaudited consolidated statements of operations. All equity-based compensation awards held by the Company's Senior Vice President and Chief Operating Officer were forfeited and the corresponding equity-based compensation totaling $4.9 million previously recorded was reversed in "General and administrative" on the unaudited consolidated statements of operations during the three months ended September 30, 2022.
Note 13—Segments
On June 29, 2021 (the "Effective Date"), the Company committed to a company-wide reorganization effort (the "Reorganization Plan") that included a workforce reduction of 14 individuals, or approximately 5% of the workforce. The reduction in workforce was communicated to employees on the Effective Date and implemented immediately, subject to certain administrative procedures. The Company operatesput the Reorganization Plan in two business segments: (i) explorationplace in order to better position the Company for the future. In connection with the Reorganization Plan, the Company incurred an aggregate of $9.8 million of one-time charges during the nine months ended September 30, 2021 comprising of compensation, tax, professional, outplacement and productioninsurance related expenses. All equity-based compensation awards held by the affected employees were forfeited and (ii) midstreamthe corresponding equity-based compensation totaling $1.1 million previously recorded was reversed in "General and marketing. The exploration and production segment is engaged inadministrative" on the acquisition, exploration and developmentunaudited consolidated statements 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.operations during the nine months ended September 30, 2021.
19

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


Note 15—Subsequent events
The following table presents selected financial information, for the periods presented, regarding the Company's operating segments on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the information forNOG Working Interest Sale
On August 16, 2022, the Company onentered into a consolidated basis:
(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)


(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 guarantors
The Guarantors have fully and unconditionally guaranteed the January 2022 Notes, the May 2022 Notes, the March 2023 Notes and the 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
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
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
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
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 owned 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 aswith Northern Oil and Gas, Inc. ("NOG"), pursuant to when and whether the additional consideration will be paid.

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


On October 20, 2017,which the Company made a capital contributionagreed to Medallionsell to NOG the Company’s working interests in certain specified non-operated oil and gas properties for an aggregate purchase price of $7.2$110.0 million, subject to fund continued expansion activitiescertain customary adjustments (the "NOG Working Interest Sale"). The NOG Working Interest Sale closed on existing portionsOctober 3, 2022, with an effective date of Medallion's pipeline infrastructure in order to gather additional third-party production.August 1, 2022.
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, 2017,7, 2022, 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, the Company borrowed $10.0repaid $40.0 million $15.0 million and $10.0 million, respectively, on the Senior Secured Credit Facility. On October 30, 2017, the Company repaid borrowings outstanding on the Senior Secured Credit Facility in the amount of $190.0 million withAs a portion of the proceeds from the Medallion Sale. Thereresult, there was no outstanding balance under the Senior Secured Credit Facility as of October 31, 2017.November 2, 2022. See Note 4 for additional discussion of the Senior Secured Credit Facility.
c.    MayOn November 1, 2022, Notes call for redemption
On October 30, 2017, the Company issued a press release announcing that it called for redemption all $500.0entered into the Tenth Amendment (the "Tenth Amendment") to the Senior Secured Credit Facility. The Tenth Amendment, among other things, (i) increases the borrowing base from $1.25 billion to $1.3 billion, (ii) permits additional senior note buybacks and other restricted payments, subject to certain conditions; and (iii) makes technical changes to permit the Company to potentially incur term loans, subject to terms to be agreed with lenders making such term loans, in addition to revolving loans, in each case, subject to the terms of the Tenth Amendment and the Senior Secured Credit Facility.
Senior unsecured notes repurchases
Subsequent to September 30, 2022, the Company repurchased $50.9 million and $9.9 million in aggregate principal amount of the January 2025 Notes and January 2028 Notes, respectively, through November 2, 2022. See Note 4 for additional discussion of the Company's senior unsecured notes repurchases.
Share repurchase program
Subsequent to September 30, 2022, the Company repurchased 112,049 shares of its Maycommon stock on the open market at a weighted-average price of $66.68 per common share for a total of $7.5 million under the share repurchase program through November 2, 2022. See Note 5 for additional discussion of the Company's share repurchases under this program.
Commodity derivatives
The following table summarizes the Company's open oil derivative positions as of September 30, 2022, Notes. The redemption dateupdated for derivative transactions entered into from September 30, 2022 through November 2, 2022, for the May 2022 Notes is November 29, 2017, and holders will receive a redemption pricesettlement periods presented:
 Remaining Year 2022Year 2023
Oil:  
WTI NYMEX - Swaps:
Volume (Bbl)92,000 — 
Weighted-average price ($/Bbl)$64.40 $— 
WTI NYMEX - Collars:
Volume (Bbl)1,407,600 4,727,000 
Weighted-average floor price ($/Bbl)$72.65 $68.09 
Weighted-average ceiling price ($/Bbl)$86.54 $83.81 
See Note 8 for additional discussion regarding the Company's derivatives. There has been no other derivative activity subsequent to September 30, 2022.
20

Table 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.Content
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:
  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

(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 and nine months ended September 30, 2022 and 2021, 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 20162021 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. Since our inception, we have grown primarily through our drilling program coupled with select strategic acquisitions and joint ventures.
Our financial and operating performance for the three months ended September 30, 2017 included the following:
Oil, NGL and natural gas sales of $157.6 million, compared to $114.8 million for the three months ended September 30, 2016;
Average daily sales volumes 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 (a non-GAAP financial measure) of $130.9 million, compared to $118.0 million for the three months ended September 30, 2016. See page 49 for a discussion and reconciliation of Adjusted EBITDA.
Our financial and operating performance for the nine months ended September 30, 2017 included the following:
Oil, NGL and natural gas sales of $438.1 million, compared to $290.5 million for the nine months ended September 30, 2016;
Average daily sales volumes of 57,044 BOE/D, compared to 48,392 BOE/D for the nine months ended September 30, 2016;
Net income of $140.4 million, compared to 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 sale
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.

May 2022 Notes call for redemption
On October 30, 2017, we issued a press release announcing that we have called for redemption the outstanding $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.
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 changes in commodity prices 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 derivative contracts that have enabled us to offset a portion of the changes in our cash flow caused by price fluctuations for our sales of oil, NGL and natural gas, as discussed in "Item 3. Quantitative and Qualitative Disclosures About Market Risk."
Core areas 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. We have grown primarily through our drilling program, coupled with select strategic acquisitions. As of September 30, 2017,2022, we had assembled 125,466165,359 net acres in the Permian Basin.
We are currently operating two drilling rigs and one completions crew which we expect to maintain for the remainder of 2022. Our planned capital expenditures for fourth-quarter 2022 are expected to be approximately $135.0 million to $145.0 million. However, we will continue to monitor commodity prices and service costs and adjust activity levels in order to proactively manage our cash flows and preserve liquidity. Below is a summary and comparative analysis of our financial and operating performance for the periods presented:
Three months ended September 30,2022 compared to 2021
(in thousands)20222021Change (#)Change (%)
Oil sales volumes (MBbl)3,219 3,250 (31)(1)%
Oil equivalents sales volumes (MBOE)7,324 7,057 267 %
Oil, NGL and natural gas sales(1)
$444,948 $311,276 $133,672 43 %
Net income$337,523 $136,832 $200,691 147 %
Net cash provided by operating activities$182,615 $97,674 $84,941 87 %
Free Cash Flow (a non-GAAP financial measure)(2)
$51,361 $(19,895)$71,256 358 %
Adjusted EBITDA (a non-GAAP financial measure)(2)
$222,790 $133,441 $89,349 67 %
_____________________________________________________________________________
(1)Our oil, NGL and natural gas sales increased as a result of a 38% increase in average sales price per BOE.
(2)See pages 37-39 for discussion and calculations of these non-GAAP financial measures.

21

Nine months ended September 30,2022 compared to 2021
(in thousands)20222021Change (#)Change (%)
Oil sales volumes (MBbl)10,536 7,840 2,696 34 %
Oil equivalents sales volumes (MBOE)22,905 21,985 920 %
Oil, NGL and natural gas sales(1)
$1,445,605 $746,059 $699,546 94 %
Net income (loss)$513,288 $(71,268)$584,556 820 %
Net cash provided by operating activities$720,702 $287,112 $433,590 151 %
Free Cash Flow (a non-GAAP financial measure)(2)
$183,404 $(27,585)$210,989 765 %
Adjusted EBITDA (a non-GAAP financial measure)(2)
$722,377 $323,755 $398,622 123 %
_____________________________________________________________________________
(1)Our oil, NGL and natural gas sales increased as a result of a 86% increase in average sales price per BOE and a 34% increase in oil sales volumes.
(2)See pages 37-39 for discussion and calculations of these non-GAAP financial measures.
Recent developments
Volatility in commodity prices
Commodity prices remained strong during the third quarter of 2022, sustaining levels reached at the end of the first quarter as increased commodity demand has continued to outpace relative supply. While recessionary concerns have placed some downward pressure on commodity prices, causing oil and gas prices to retreat from their earlier highs in 2022, worldwide commodity demand continues to exceed pre-COVID-19 pandemic levels. Although supply has increased, it has been constrained and pricing has been affected, in part, by the impact of the Russian-Ukrainian military conflict on global commodity and financial markets, and the resulting effect of sanctions by the European Union, United Kingdom and U.S. on imports of oil and gas from Russia, as well as a recent announcement by OPEC+ of oil production cuts of two million barrels per day beginning in November of 2022. However, because any of the above factors could suddenly change or reverse, global commodity and financial markets remain subject to heightened levels of uncertainty and volatility, and future disruptions and industry-specific impacts could result.
Rising inflation and interest rates
Reversing a trend experienced in 2020 in connection with the impact of COVID-19 and historically low crude oil prices, drilling and completions costs and costs of oilfield services, equipment, and materials began to rise in 2021 and have continued to persist at elevated levels in 2022 in conjunction with the significant increase in commodity prices, labor tightening, supply chain disruptions caused by the COVID-19 pandemic and the resulting limited availability of certain materials and products manufactured using such materials and heightened levels of inflation. In addition to the effect of such inflationary pressures on our operating costs, rising interest rates as a result of the Federal Reserve’s tightening monetary policy have the potential to increase our borrowing costs on debt under our Senior Secured Credit Facility. We remain committed to our ongoing efforts to increase the efficiency of our operations and improve costs, which may, in part, offset cost increases from inflation and reduce our borrowing needs.
See Note 15 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for discussion of recent developments that have occurred subsequent to September 30, 2022.
Pricing and reserves
Our results of operations are heavily influenced by oil, NGL and natural gas prices. Historically, commodity prices have experienced significant fluctuations; however, the volatility in prices has substantially increased in recent years. We maintain an active, multi-year commodity derivatives strategy to minimize commodity price volatility and support cash flows needed for operations. 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 and 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 8 and 9 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our commodity derivatives. Notwithstanding our derivatives strategy, another collapse in commodity prices may affect the economic viability of, and our ability to fund, our drilling projects, as well as the economic recovery of oil, NGL and natural gas reserves. See "Critical accounting estimates" in "Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of
22

Operations" of the 2021 Annual Report for further discussion of our oil, NGL and natural gas reserve quantities and standardized measure of discounted future net cash flows.
Our reserves are reported in three streams: oil, NGL and natural gas. The Realized Prices, which are utilized to value our proved reserves and calculated using the average first-day-of-the-month prices for each month within the 12-month period prior to the end of the reporting period, adjusted for factors affecting price received at the delivery point, as of September 30, 2022 were $92.54 for oil, $32.38 for NGL and $4.34 for natural gas. The unamortized cost of evaluated oil and natural gas properties being depleted did not exceed the full cost ceiling as of September 30, 2022 and September 30, 2021. As such, no full cost ceiling impairments were recorded during the nine months ending September 30, 2022 and September 30, 2021. Additionally, if prices remain at current levels we do not anticipate recording any full cost ceiling impairments for the foreseeable future. See Notes 2 and 6 in our 2021 Annual Report for discussion of the full cost method of accounting and our Realized Prices.
Results of operations
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 2 in our revenues were comprised of: 54% sales2021 Annual Report for additional information regarding our revenue recognition policies.
The following tables present 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 September 30,2022 compared to 2021
20222021Change (#)Change (%)
Oil sales67 %60 %12 %
NGL sales13 %13 %— — %
Natural gas sales16 %10 %60 %
Midstream service revenues— %— %— — %
Sales of purchased oil%17 %(13)(76)%
Total100 %100 %
Nine months ended September 30,2022 compared to 2021
20222021Change (#)Change (%)
Oil sales69 %56 %13 23 %
NGL sales13 %14 %(1)(7)%
Natural gas sales11 %11 %— — %
Midstream service revenues— %— %— — %
Sales of purchased oil%19 %(12)(63)%
Total100 %100 %


23


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 forthtables present 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 September 30,2022 compared to 2021
20222021Change (#)Change (%)
Sales volumes:  
Oil (MBbl)3,219 3,250 (31)(1)%
NGL (MBbl)2,034 1,830 204 11 %
Natural gas (MMcf)12,430 11,860 570 %
Oil equivalents (MBOE)(1)(2)
7,324 7,057 267 %
Average daily oil equivalent sales volumes (BOE/D)(2)
79,613 76,703 2,910 %
Average daily oil sales volumes (Bbl/D)(2)
34,994 35,329 (335)(1)%
Sales revenues (in thousands):  
Oil$311,740 $229,329 $82,411 36 %
NGL59,377 47,949 11,428 24 %
Natural gas73,831 33,998 39,833 117 %
Total oil, NGL and natural gas sales revenues$444,948 $311,276 $133,672 43 %
Average sales prices(2):
  
Oil ($/Bbl)(3)
$96.83 $70.56 $26.27 37 %
NGL ($/Bbl)(3)
$29.20 $26.20 $3.00 11 %
Natural gas ($/Mcf)(3)
$5.94 $2.87 $3.07 107 %
Average sales price ($/BOE)(3)
$60.75 $44.11 $16.64 38 %
Oil, with commodity derivatives ($/Bbl)(4)
$71.09 $53.94 $17.15 32 %
NGL, with commodity derivatives ($/Bbl)(4)
$24.47 $9.31 $15.16 163 %
Natural gas, with commodity derivatives ($/Mcf)(4)
$3.35 $1.45 $1.90 131 %
Average sales price, with commodity derivatives ($/BOE)(4)
$43.74 $29.70 $14.04 47 %

(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 transactions on our average sales prices. Our calculation of such after-effects includes current period settlements of matured derivatives in accordance with GAAP
(2)The numbers presented in the three months ended September 30, 2022 and 2021 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 settlements of matured commodity derivatives during the respective periods 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.
24

 Nine months ended September 30,2022 compared to 2021
20222021Change (#)Change (%)
Sales volumes:  
Oil (MBbl)10,536 7,840 2,696 34 %
NGL (MBbl)6,128 6,702 (574)(9)%
Natural gas (MMcf)37,447 44,659 (7,212)(16)%
Oil equivalents (MBOE)(1)(2)
22,905 21,985 920 %
Average daily oil equivalent sales volumes (BOE/D)(2)
83,901 80,530 3,371 %
Average daily oil sales volumes (Bbl/D)(2)
38,594 28,717 9,877 34 %
Sales revenues (in thousands):  
Oil$1,069,542 $514,752 $554,790 108 %
NGL197,037 133,121 63,916 48 %
Natural gas179,026 98,186 80,840 82 %
Total oil, NGL and natural gas sales revenues$1,445,605 $746,059 $699,546 94 %
Average sales prices(2):
  
Oil ($/Bbl)(3)
$101.51 $65.66 $35.85 55 %
NGL ($/Bbl)(3)
$32.16 $19.86 $12.30 62 %
Natural gas ($/Mcf)(3)
$4.78 $2.20 $2.58 117 %
Average sales price ($/BOE)(3)
$63.11 $33.94 $29.17 86 %
Oil, with commodity derivatives ($/Bbl)(4)
$71.03 $49.33 $21.70 44 %
NGL, with commodity derivatives ($/Bbl)(4)
$25.93 $10.40 $15.53 149 %
Natural gas, with commodity derivatives ($/Mcf)(4)
$3.05 $1.53 $1.52 99 %
Average sales price, with commodity derivatives ($/BOE)(4)
$44.60 $23.86 $20.74 87 %

(1)BOE is calculated using a conversion rate of six Mcf per one Bbl.
(2)The numbers presented in the nine months ended September 30, 2022 and 2021 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 settlements of matured commodity derivatives during the respective periods and an adjustment to reflect premiums incurred previously or upon settlement that are attributable to commodity derivatives that settled during the respective periods.
25

The following tables present net settlements paid 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) $(6,972)
and the corresponding changes for such periods:     
Three months ended September 30,2022 compared to 2021
(in thousands)20222021Change ($)Change (%)
Net settlements paid for matured commodity derivatives:
Oil$(82,862)$(43,838)$(39,024)(89)%
NGL(9,618)(30,905)21,287 69 %
Natural gas(32,131)(16,747)(15,384)(92)%
Total$(124,611)$(91,490)$(33,121)(36)%
Net premiums paid previously or upon settlement attributable to commodity derivatives that matured during the respective period:
Oil$— $(10,182)$10,182 100 %
Nine months ended September 30,2022 compared to 2021
(in thousands)20222021Change ($)Change (%)
Net settlements paid for matured commodity derivatives:
Oil$(321,106)$(96,675)$(224,431)(232)%
NGL(38,152)(63,434)25,282 40 %
Natural gas(64,694)(30,046)(34,648)(115)%
Total$(423,952)$(190,155)$(233,797)(123)%
Net premiums paid previously or upon settlement attributable to commodity derivatives that matured during the respective period:
Oil$— $(31,370)$31,370 100 %
Changes in average realized sales prices and sales volumes caused the following changes to our oil, NGL and natural gas revenues between the three and nine months ended September 30, 20172022 and 2016:2021:
(in thousands)OilNGLNatural gasTotal 
Third-quarter 2021 Revenues$229,329 $47,949 $33,998 

$311,276 
Effect of changes in average sales prices84,586 6,095 38,199 128,880 
Effect of changes in sales volumes(2,175)5,333 1,634 4,792 
Third-quarter 2022 Revenues$311,740 $59,377 $73,831 $444,948 
Change ($)$82,411 $11,428 $39,833 $133,672 
Change (%)36 %24 %117 %43 %
(in thousands)OilNGLNatural gasTotal 
Third-quarter year-to-date 2021 Revenues$514,752 $133,121 $98,186 

$746,059 
Effect of changes in average sales prices377,743 75,324 96,696 549,763 
Effect of changes in sales volumes177,047 (11,408)(15,856)149,783 
Third-quarter year-to-date 2022 Revenues$1,069,542 $197,037 $179,026 $1,445,605 
Change ($)$554,790 $63,916 $80,840 $699,546 
Change (%)108 %48 %82 %94 %
The increase in our third-quarter 2022 oil revenues as compared to the same period in 2021 is primarily due to an increase in oil price. The increase in our third-quarter year-to-date 2022 oil revenues as compared to the same period in 2021 is primarily due to (i) an increase in oil price and (ii) the Sabalo/Shad Acquisition and Pioneer Acquisition, both of which occurred during the second half of 2021, and the related increase in our oil sales volumes.
26

(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
ChangesThe increase in average realized sales prices and sales volumes caused the following changes to our oil,third-quarter 2022 NGL and natural gas revenues betweenas compared to the same period in 2021 is primarily due to increases in NGL and natural gas prices. The increase in our third-quarter year-to-date 2022 NGL and natural gas revenues as compared to the same period in 2021 is primarily due to increases in NGL and natural gas prices, partially offset by the Working Interest Sale, which occurred during the second half of 2021, and the related decrease in our NGL and natural gas sales volumes.
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. During the three and nine months ended September 30, 20172022, we were a firm shipper on the Gray Oak pipeline 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. Ourwe utilized purchased oil revenueto fulfill portions of our commitments. In previous periods, we also utilized purchased oil to fulfill portions of our Bridgetex pipeline commitment, which ended during the first quarter of 2022. The continuance of this practice in the future is based upon, among other factors, our pipeline capacity as a functionfirm shipper and the quantity of our lease production which may contribute to our pipeline commitments. Sales of purchased oil production volumes sold and average sales prices received for those volumes. The increase in oil revenue of $26.1 million, or 31%, fordecreased during the three months ended September 30, 2017 as compared to 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 as2022 compared to the nine months ended September 30, 2016 issame periods in 2021 primarily due to a 26% increasedecrease in averagethe volumes of purchased oil prices realized and a 14% increase in oil sales volumes.
NGL revenue. Our NGL revenue is a functionas our Bridgetex pipeline commitment ended during the first quarter 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 compared to the three months ended September 30, 2016 is due to a 61% increase in average NGL prices realized and a 17% increase in NGL sales volumes.
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 volumes2022, partially offset by a 1% decreasean increase in average natural gas prices realized.

sales prices.
The increase in natural gas revenuefollowing tables present sales of $21.8 million, or 64%,purchased oil for the nine months ended September 30, 2017 as compared toperiods presented and 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.corresponding changes for such periods:
 
 
Three months ended September 30,2022 compared to 2021
(in thousands) 20222021Change ($)Change (%)
Sales of purchased oil$18,371 $66,235 $(47,864)(72)%
 
 
Nine months ended September 30,2022 compared to 2021
(in thousands) 20222021Change ($)Change (%)
Sales of purchased oil$106,030 $173,500 $(67,470)(39)%

27

Costs and expenses
The following table sets forthtables present 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 September 30,2022 compared to 2021
(in thousands except for per BOE sold data) 2017 2016 2017
2016(in thousands except for per BOE sold data)20222021Change ($)Change (%)
Costs and expenses:  
  
  
  
Costs and expenses:  
Lease operating expenses $19,594
 $18,177
 $56,690
 $57,920
Lease operating expenses$44,246 $29,837 $14,409 48 %
Production and ad valorem taxes 9,558
 7,066
 26,811
 21,483
Production and ad valorem taxes29,024 17,937 11,087 62 %
Transportation and marketing expensesTransportation and marketing expenses13,285 11,660 1,625 14 %
Midstream service expenses 1,174
 1,039
 2,986
 2,826
Midstream service expenses769 1,014 (245)(24)%
Costs of purchased oil 47,385
 44,232
 141,661
 121,190
Costs of purchased oil18,772 68,805 (50,033)(73)%
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)14,831 11,332 3,499 31 %
General and administrative (LTIP):General and administrative (LTIP):
LTIP cashLTIP cash(3,782)2,065 (5,847)(283)%
LTIP non-cashLTIP non-cash808 1,611 (803)(50)%
Organizational restructuring expensesOrganizational restructuring expenses10,420 — 10,420 100 %
Depletion, depreciation and amortization 41,212
 35,158
 113,327
 110,813
Depletion, depreciation and amortization74,928 62,678 12,250 20 %
Impairment expense 
 
 
 162,027
Other operating expenses 1,443
 2,465
 3,906
 4,169
Total $145,366
 $134,242
 $417,986
 $546,486
Average costs per BOE sold(1):






    
Other operating expense, netOther operating expense, net1,772 1,798 (26)(1)%
Total costs and expensesTotal costs and expenses$205,073 $208,737 $(3,664)(2)%
Gain on disposal of assets, netGain on disposal of assets, net4,282 95,201 (90,919)(96)%
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$6.04 $4.23 $1.81 43 %
Production and ad valorem taxes 1.73
 1.50
 1.72
 1.62
Production and ad valorem taxes3.96 2.54 1.42 56 %
Midstream service expenses 0.21
 0.22
 0.19
 0.21
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
Transportation and marketing expensesTransportation and marketing expenses1.81 1.65 0.16 10 %
General and administrative (excluding LTIP)General and administrative (excluding LTIP)2.02 1.61 0.41 25 %
Total selected operating expensesTotal selected operating expenses$13.83 $10.03 $3.80 38 %
General and administrative (LTIP):General and administrative (LTIP):
LTIP cashLTIP cash$(0.52)$0.29 $(0.81)(279)%
LTIP non-cashLTIP non-cash$0.11 $0.23 $(0.12)(52)%
Depletion, depreciation and amortization 7.46

7.45

7.28

8.36
Depletion, depreciation and amortization$10.23 $8.88 $1.35 15 %
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.
28

 Nine months ended September 30,2022 compared to 2021
(in thousands except for per BOE sold data)20222021Change ($)Change (%)
Costs and expenses:  
Lease operating expenses$127,136 $68,526 $58,610 86 %
Production and ad valorem taxes89,512 45,957 43,555 95 %
Transportation and marketing expenses39,022 34,477 4,545 13 %
Midstream service expenses3,916 2,572 1,344 52 %
Costs of purchased oil108,516 183,458 (74,942)(41)%
General and administrative (excluding LTIP)41,729 33,479 8,250 25 %
General and administrative (LTIP):
LTIP cash3,606 10,905 (7,299)(67)%
LTIP non-cash5,465 4,798 667 14 %
Organizational restructuring expenses10,420 9,800 620 %
Depletion, depreciation and amortization226,555 140,763 85,792 61 %
Impairment expense— 1,613 (1,613)(100)%
Other operating expense, net2,947 4,099 (1,152)(28)%
Total costs and expenses$658,824 $540,447 $118,377 22 %
Gain on disposal of assets, net4,952 93,454 (88,502)(95)%
Selected average costs and expenses per BOE sold(1):
Lease operating expenses$5.55 $3.12 $2.43 78 %
Production and ad valorem taxes3.91 2.09 1.82 87 %
Transportation and marketing expenses1.70 1.57 0.13 %
General and administrative (excluding LTIP)1.82 1.52 0.30 20 %
Total selected operating expenses$12.98 $8.30 $4.68 56 %
General and administrative (LTIP):
LTIP cash$0.16 $0.50 $(0.34)(68)%
LTIP non-cash$0.24 $0.22 $0.02 %
Depletion, depreciation and amortization$9.89 $6.40 $3.49 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.

Lease operating expenses ("LOE"). LOE, which includeincludes workover expenses, increased by $1.4 million, or 8%, and decreased by $1.2 million, or 2%, for the three and nine months ended September 30, 2017, respectively,2022, compared to the same periods in 2016. On a per BOE sold basis, lease operating2021. LOE are daily expenses decreased 8%incurred to bring oil, NGL and 17% fornatural gas out of the threeground and nine months ended September 30, 2017, respectively, compared to market, together with the same periods in 2016 mainlydaily expenses incurred to maintain our producing properties. Such costs also include maintenance, repairs and non-routine workover expenses related to our oil and natural gas properties. LOE increased during 2022 due to previous investments in field infrastructure.inflationary pressures and costs associated with integrating our assets from the Sabalo/Shad Acquisition and Pioneer Acquisition, primarily driven by costs related to artificial lift and flowback management. We continue to focus on economic efficiencies associated with the usage and procurement of products and services related to lease operating expenses.LOE.Total LOE is expected to remain relatively flat for the remainder of the year, with unit LOE increasing as total volumes are expected to decline.
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,2022, compared to the same periods in 2016. The quarter-over-quarter increase is2021, due to a $1.5 million increase in production taxesincreased oil, NGL 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.natural gas sales revenues. 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 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 service
29

Transportation 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&A decreased by $1.1 million, or 4%, andmarketing expenses increased by $6.5 million, or 10%, for the three and nine months ended September 30, 2017, respectively,2022, 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 fees2021. These are expenses incurred for the three months ended September 30, 2017 compareddelivery of produced oil to customers in the U.S. Gulf Coast market via the Gray Oak pipeline and, in previous periods, the Bridgetex pipeline. We ship the majority of our produced oil to the same period in 2016. The year-to-date increase overU.S. Gulf Coast, which we believe provides a long-term pricing advantage versus the comparable period in 2016 is mainly due to an increase in stock-based compensation, net 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 compared to the same period in 2016.
The fair values for each of our restricted stock awards issued were calculated basedMidland 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 10 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information regarding our stock-based compensation.
Depletion, depreciation and amortization ("DD&A"). The following table sets forth the componentsdiscussion of our DD&A fortransportation commitments.
Costs of purchased oil. During the three and nine months ended September 30, 2022, we were a firm shipper on the Gray Oak pipeline and we utilized purchased oil to fulfill portions of our commitments. In previous periods, presented:
  Three months ended September 30, Nine months ended September 30,
(in thousands except for per BOE sold data) 2017 2016 2017 2016
Depletion of evaluated oil and natural gas properties $37,538
 $31,679
 $102,290
 $100,136
Depreciation of midstream service assets 2,241
 2,036
 6,569
 6,204
Depreciation and amortization of other fixed assets 1,433
 1,443
 4,468
 4,473
Total DD&A $41,212
 $35,158
 $113,327
 $110,813
DD&A increased by $6.1 million, or 17%, and $2.5 million, or 2%,we also utilized purchased oil to fulfill portions of our Bridgetex pipeline commitment, which ended during the first quarter of 2022. In the event our long-haul transportation capacity on the 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. Costs of purchased oil decreased for the three and nine months ended September 30, 2017, respectively,2022, compared to the same periods in 2016. The quarter-over-quarter2021 primarily due to a decrease in the volumes of purchased oil on pipelines as our Bridgetex pipeline commitment ended during the first quarter of 2022, partially offset by an increase isin sales prices.
General and administrative ("G&A"). G&A, excluding employee compensation expenses from our long-term incentive plan ("LTIP"), increased for the three and nine months ended September 30, 2022, compared to the same period in 2021, mainly due to an increase(i) increases in production volumes soldworkforce and professional expenses and (ii) inflationary pressures.
LTIP cash expense decreased for the three and nine months ended September 30, 2022, compared to the same periods in 2021. These decreases are primarily due to (i) forfeitures of cash-settled performance unit awards in connection with the departure of our former Senior Vice President and Chief Operating Officer during the third quarter of 2022 and (ii) a decrease in the fair values of our cash-settled LTIP awards during the third quarter of 2022, mainly due to the performance of our stock during the period.
LTIP non-cash expense decreased for the three months ended September 30, 20172022, compared to the same period in 2016. On a per BOE sold basis, DD&A decreased2021, mainly due to forfeitures of share-settled LTIP awards in connection with the departure of our former Senior Vice President and Chief Operating Officer during the third quarter of 2022. LTIP non-cash expense increased for the nine months ended September 30, 20172022, compared to the same period in 2016,2021, mainly due to positive well resultsnew share-settled LTIP awards granted to our employees during the second half of 2021 and the impactfirst half of 2022, and partially offset by forfeitures of share-settled LTIP awards in connection with the departure of our full cost ceiling impairment of $161.1 million recorded as of March 31, 2016.
Impairment expense. Our net book value of evaluated oilformer Senior Vice President 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 recordedChief Operating Officer during the nine months ended September 30, 2017. For further discussionthird quarter of our non-cash full cost ceiling impairment accounting policy, see2022. See Note 2.g6 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report. There were no long-lived assets impairments recorded duringReport for information regarding our equity-based compensation.
Organizational restructuring expenses. Organizational restructuring expenses increased for the three and nine months ended September 30, 2017 or 2016. Inventory impairments of $1.0 million2022, compared to the same periods in 2021. Such expenses were recordedincurred for (i) the nine months ended September 30, 2016. There were no inventory impairments recordeddeparture our former Senior Vice President and Chief Operating Officer during the nine months ended September 30, 2017. For further discussionthird quarter of long-lived assets2022 and inventory impairment accounting policies, see(ii) a workforce reduction during the second quarter of 2021. See Note 2.i14 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.Report for information regarding our organizational restructurings.

Gain on disposal of assets, net. Gain on disposal of assets, net, decreased for the three and nine months ended September 30, 2022, compared to the same periods in 2021, primarily due to the gain recorded in third-quarter 2021 in connection with the Working Interest Sale. See Note 3to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion regarding the gain on the Working Interest Sale. 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 on the volume of the assets disposed, their associated net book value and, in the case of a disposal by sale, the sale price.

30

Depletion, depreciation and amortization ("DD&A"). The following tables present depletion expense per BOE sold for the periods presented and the corresponding changes for such periods:
Three months ended September 30,2022 compared to 2021
(in thousands)20222021Change ($)Change (%)
Depletion expense per BOE sold$9.79 $8.40 $1.39 17 %
Nine months ended September 30,2022 compared to 2021
(in thousands)20222021Change ($)Change (%)
Depletion expense per BOE sold$9.46 $5.94 $3.52 59 %
Depletion expense per BOE increased for the three and nine months ended September 30, 2022, compared to the same periods in 2021, primarily due to (i) an increase in the book value of our oil and natural gas properties as a result of the Sabalo/Shad Acquisition and Pioneer Acquisition and the associated development costs and (ii) inflationary pressures. See Note 6 to our consolidated financial statements included in our 2021 Annual Report and "—Pricing and reserves" for additional information regarding the full cost method of accounting.
Other operating expense, net. These costs include accretion expense due to the passage of time on our asset retirement obligations. See Note 2 in our 2021 Annual Report for additional information regarding our asset retirement obligations.
Non-operating income (expense)
The following table sets forthtables present 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) $(108,896)
 Three months ended September 30,2022 compared to 2021
(in thousands)20222021Change ($)Change (%)
Gain (loss) on derivatives, net$100,748 $(96,240)$196,988 205 %
Interest expense(30,967)(30,406)(561)(2)%
Gain extinguishment of debt, net553 — 553 100 %
Other income, net98 441 (343)(78)%
Total non-operating expense, net$70,432 $(126,205)$196,637 156 %
 Nine months ended September 30,2022 compared to 2021
(in thousands)20222021Change ($)Change (%)
Loss on derivatives, net$(290,995)$(467,547)$176,552 38 %
Interest expense(96,251)(82,222)(14,029)(17)%
Loss extinguishment of debt, net(245)— (245)(100)%
Other income, net433 2,236 (1,803)(81)%
Total non-operating expense, net$(387,058)$(547,533)$160,475 29 %
Gain (loss) on derivatives, net. The following table presentstables present the changes in the components of gain (loss) on derivatives, net for the periods presented:presented and the corresponding changes for such periods:
Three months ended September 30,2022 compared to 2021
(in thousands)20222021Change ($)Change (%)
Non-cash gain (loss) on derivatives, net$225,037 $(3,514)$228,551 6,504 %
Settlements paid for matured derivatives, net(124,289)(92,726)(31,563)(34)%
Gain (loss) on derivatives, net$100,748 $(96,240)$196,988 205 %
31

(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) $81,910
Nine months ended September 30,2022 compared to 2021
(in thousands)20222021Change ($)Change (%)
Non-cash gain (loss) on derivatives, net$131,118 $(285,081)$416,199 146 %
Settlements paid for matured derivatives, net(423,668)(191,507)(232,161)(121)%
Settlements received for contingent consideration1,555 — 1,555 100 %
Premiums received for commodity derivatives— 9,041 (9,041)(100)%
Loss on derivatives, net$(290,995)$(467,547)$176,552 38 %
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 initial valuation 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) 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 market prices. Net cash settlementsSettlements paid or received for matured derivatives are for our (i) commodity derivative contracts, which are based on the cash settlement prices of our matured derivatives compared to the prices specified in the derivative contracts.
During the nine months ended September 30, 2017, we received proceeds from a hedge restructuring in which we early terminated acontracts, (ii) interest rate derivative contract swap, resulting in a termination amount due to us of $4.2 million. The $4.2 million was settled in full by applying the proceeds to pay the premium on one new derivative contract collar entered into during 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 part of the hedge restructuring.and (iii) contingent consideration derivatives.
See Notes 2.e, 78 and 8.a9 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 million forDuring the three and nine months ended September 30, 2017, respectively, comparedthird quarter of 2021, we completed the offering of the July 2029 Notes, with interest payable semi-annually commencing January 31, 2022 with interest from closing 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%that date. The increase 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, 2017 compared to the same period in 2016 due to the increases in oil prices. For these sales2022 reflects a full year-to-date of purchased oil, we

purchase oil from third parties in West Texas, transport it on the Bridgetex Pipeline and sell it to a third party in the Houston market. The net lossinterest expense incurred 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 $20.5 million, or 17%, for the nine months ended September 30, 2017 compared to the same period in 2016 primarily due to the increases in oil prices. These costs include purchasing oil from third parties and transporting it on the Bridgetex Pipeline.
Income from equity method investee. As of September 30, 2017, LMS owned 49% of the ownership units of Medallion. Subsequent to September 30, 2017, LMS and MMH consummated the sale of 100% of the ownership interests in Medallion to an affiliate of GIP.July 2029 Notes. See Note 16.a4 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information regarding this sale.our long-term debt.
Prior toIncome tax benefit (expense)
The following tables present income tax benefit (expense) for the sale, weaccounted for our investment in Medallion under the equity method of accounting with our proportionate share of net income reflected in the unaudited consolidated statements of operations as "Income from equity method investee"periods presented and the carrying amount reflected incorresponding changes for such periods:
Three months ended September 30,2022 compared to 2021
(in thousands)20222021Change ($)Change (%)
Current$960 $(1,300)$2,260 174 %
Deferred$2,808 $(1,377)$4,185 304 %
Nine months ended September 30,2022 compared to 2021
(in thousands)20222021Change ($)Change (%)
Current$(4,771)$(1,300)$(3,471)(267)%
Deferred$2,324 $707 $1,617 229 %
We are subject to federal and state income taxes and the unaudited consolidated balance sheets as "Investment in equity method investee." Income from equity method investee increased by $2.1 million and $1.7 million, or 795% and 26%,Texas franchise tax. The income tax benefit (expense) for the three and nine months ended September 30, 2017, respectively, compared2022 is attributed to Texas franchise tax, due to a full valuation allowance recorded against the federal and Oklahoma deferred tax assets.
If we were to experience an "ownership change" as determined under Section 382 of the Internal Revenue Code, our ability to offset taxable income arising after the ownership change with net operating losses arising prior 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 endedownership change would be limited. As of September 30, 2017, Medallion continued expansion activities2022, no such ownership change has occurred.
With the rise in oil prices and the addition of oily, high-margin inventory, we have seen positive indications that we will use our NOLs. We utilized $244.8 million of our NOLs on existing portionsour 2021 tax return and expect to utilize a comparable amount on our 2022 tax return. However, as 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 for the three months ended September 30, 20172022, we believe it is more likely than not that a portion of the NOL loss carryforwards are not fully realizable. We continue to consider new evidence, both positive and 2016, respectively,negative, in determining whether, based on the weight of that evidence, a valuation allowance is needed. Such consideration includes projected future cash flows from our oil, NGL and an averagenatural gas reserves (including the timing of 166,168 BOPD and 100,000 BOPD forthose cash flows), the nine months endedreversal of deferred tax
32

liabilities recorded as of September 30, 20172022, and 2016, respectively.our ability to capitalize intangible drilling costs, rather than expensing these costs and future projections of Oklahoma sourced income. A significant item of objective negative evidence considered was the cumulative historical three-year pre-tax loss and a net deferred tax asset position at September 30, 2022.
SeeWe currently believe it is reasonably possible we could achieve a three-year cumulative level of profitability within the next 12 months, which would enhance our ability to conclude that it is more likely than not that the deferred tax assets would be realized and support a release of the valuation allowance. However, the exact timing and amount of the release is unknown at this time. As long as we continue to conclude that the valuation allowance recorded against our net deferred tax assets is necessary, we will not have significant deferred income tax expense or benefit. The valuation allowance does not preclude us from utilizing the tax attributes if we recognize taxable income.
On August 16, 2022, the Inflation Reduction Act of 2022 was signed into U.S. law. The IRA includes various tax provisions, including a 1% excise tax on stock repurchases made by publicly traded U.S. corporations, expanded tax credits for clean energy incentives and a 15% corporate alternative minimum tax that applies to certain corporations with adjusted financial statement income in excess of $1.0 billion. The Company is evaluating the IRA and its requirements, as well as the potential impact of the IRA to its business. For additional discussion of our income taxes, see Note 2.h, 12.a and 16.a12 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information regarding this investment.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. We believe cash flows from operations (including our hedging program) and availability under our Senior Secured Credit Facility provide sufficient liquidity to manage our cash needs and contractual obligations and to fund expected capital expenditures. Our primary operational uses of capital have been for the acquisition, exploration and development of oil and natural gas properties LMS'and infrastructure developmentdevelopment. During the third quarter of 2022, we have utilized our cash flows to fund the repurchase of portions of our senior unsecured notes 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 proportionateour 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-closingrepurchase program. For 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 portiondiscussion 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 amountrepurchase of our May 2022 Notes. Seesenior unsecured notes and our share repurchase program, see Notes 16.b4 and 16.c5, respectively, to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information.Report.
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 seek to maintain a financial profile that provides operational flexibility and monitor the capital markets and our capital structure andto 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. We continuously look for other opportunities to maximize shareholder value. For further discussion of our financing activities related to debt instruments, see Notes 4 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.
Due to the inherent volatility in the prices of oil, NGL and natural gas and the sometimes wide pricing differentials between where we produce and sell such commodities, we engage in commodity derivative transactions to hedge price risk associated with a portion of our anticipated sales volumes. Due to the inherent volatility in interest rates, we will, from time to time, enter into interest rate derivative swaps to hedge interest rate risk associated with our debt under the Senior Secured Credit Facility. By removing a portion of the price volatility associated with future sales volumes, we expect to mitigate, but not eliminate, the potential effects of variability in cash flows from operations. See "Part I. Item 3. Quantitative and Qualitative Disclosures About Market Risk" below. See Note 9 to our consolidated financial statements included elsewhere in this Quarterly Report for discussion of our open commodity positions.
As of September 30, 2022, we had cash and cash equivalents of $49.9 million and available capacity under the Senior Secured Credit Facility of $960.0 million, resulting in total liquidity of $1.0 billion. As of November 2, 2022, we had cash and cash equivalents of $53.9 million and full available capacity under the Senior Secured Credit Facility of $1.0 billion, resulting in total liquidity of $1.1 billion. We believe that our operating cash flows and the aforementioned liquidity sources provide us with sufficient liquidity and financial resources to manage our cash needs and contractual obligations, to implement our currently planned capital expenditure budget and, at our discretion, to fund any share repurchases, pay down, repurchase or refinance
33

debt or adjust our planned capital expenditure budget.
Cash requirements for known contractual and other obligations
The following table presents significant cash requirements for known contractual and other obligations as of September 30, 2022:
(in thousands)
Short-term(1)
Long-termTotal
Senior unsecured notes(2)
$106,495 $1,517,430 $1,623,925 
Senior Secured Credit Facility(3)
— 40,000 40,000 
Asset retirement obligations(4)
3,183 70,063 73,246 
Firm transportation commitments(5)
17,217 60,282 77,499 
Performance unit award cash payouts(6)
6,644 7,926 14,570 
Lease commitments(7)
18,906 14,762 33,668 
Total$152,445 $1,710,463 $1,862,908 
_____________________________________________________________________________
(1)We expect to satisfy our short-term contractual and other obligations with cash flows from operations.
(2)Amounts presented include both our principal and interest obligations. The July 2029 Notes consist of $298.2 million in principal and interest payments totaling $23.1 million each year with interest payments due semi-annually on January 31 and July 31 of each year until July 31, 2029. The January 2025 Notes and January 2028 Notes consist of $529.5 million and $326.8 million in principal, respectively, and interest payments totaling $50.3 million and $33.1 million each year, respectively, with interest payments due semi-annually on January 15 and July 15 of each year until January 15, 2025 and January 15, 2028, respectively.
(3)The $40.0 million principal on our Senior Secured Credit facility is due on July 16, 2025. Amounts presented do not include future loan advances, repayments, commitment fees or other fees on our Senior Secured Credit Facility as we cannot determine with accuracy the timing of such items. Additionally, amounts presented do not include interest expense as it is a floating rate instrument and we cannot determine with accuracy the future interest rates to be charged. See Notes 34 and 415 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our divestiture of oil and natural gas properties 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
(4)Asset retirement obligations represent future costs associated with the financial resources to implement our planned exploration and development activities.
We use derivatives to reduce exposure to fluctuations in the pricesretirement of oil, NGL and natural gas.tangible long-lived assets. See Note 7.a2 in our 2021 Annual Report for additional information regarding our asset retirement obligations.
(5)Amounts represent commitments to deliver, for sale or transportation, fixed volumes of product under certain contractual arrangements that specify the delivery of a fixed and determinable quantity. See Note 10 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for information regardingadditional discussion of our derivative settlement indices and our open hedge positionsfirm transportation commitments.
(6)Amounts represent the estimated cash payouts as of September 30, 2017. As of November 2, 2017, we have not entered into additional hedges subsequent to2022 for our performance unit awards granted on March 5, 2020 and March 9, 2021, utilizing our September 30, 2017. By removing a significant portion of the price volatility associated with future production, we expect2022 closing stock price. See Note 9 to mitigate, but not eliminate, the potential effects of variabilityour consolidated financial statements included in cash flows from operations due to fluctuations in commodity prices. Our derivative positions will help us stabilize a portionour 2021 Annual Report for additional discussion of our expected cash flows from operationsperformance unit awards.
(7)Lease commitment amounts represent our minimum lease payments for our operating lease liabilities. We have committed to drilling rig contracts with third parties to facilitate our drilling plans. Amounts presented include the gross amount we are committed to pay for the drilling rig contract. However, we will record our proportionate share based on our working interest in our consolidated financial statements as incurred. Management does not currently anticipate the eventearly termination of future declinesthese contracts in the prices2022. See Note 5 to our consolidated financial statements included in our 2021 Annual Report for additional discussion of oil, NGLour leases and natural gas. See "Item 3. Quantitative and Qualitative Disclosures About Market Risk" below.Note 10 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our drilling rig contracts.

34

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, Nine months ended September 30,2022 compared to 2021
(in thousands) 2017 2016(in thousands)20222021Change ($)Change (%)
Net cash provided by operating activities $272,051
 $245,454
Net cash provided by operating activities$720,702 $287,112 $433,590 151 %
Net cash used in investing activities (356,893) (455,895)Net cash used in investing activities(443,475)(517,750)74,275 14 %
Net cash provided by financing activities 72,988
 209,647
Net decrease in cash and cash equivalents $(11,854) $(794)
Net cash (used in) provided by financing activitiesNet cash (used in) provided by financing activities(284,084)233,277 (517,361)(222)%
Net (decrease) increase in cash and cash equivalentsNet (decrease) increase in cash and cash equivalents$(6,857)$2,639 $(9,496)(360)%
Cash flows from operating activities
Net cash provided by operating activities increased by $26.6 million forduring the nine months ended September 30, 20172022, compared to the same period in 2016 mainly due to the price-related2021. Notable cash changes include (i) an increase in total oil, NGL and natural gas revenues; however, notable cash changes included (i)sales revenues of $699.5 million, (ii) a decrease of $125.2$241.2 million due to changes in cashnet settlements received for matured and early terminations of derivatives, net of premiums, paid, (ii) a cash outflow of $6.4 million relatedmainly due to the settlement of our last tranche of performance unit awardsincreases in first-quarter 2016 with no comparable amount incurred in 2017commodity prices and (iii) an increase of $85.7 million due to net changes in operating assets and liabilities. Other significant changes include an increase in lease operating expense and production and ad valorem taxes. The increase in total oil, NGL and natural gas sales revenues was due to a decrease86% increase in working capital outflowsaverage sales price per BOE as well as a 34% increase in oil volumes sold. For additional information, see "—Results of $1.2 million.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. 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 2021 Annual Report.
Cash flows from investing activities
Net cash used in investing activities decreased $99.0 million duringfor the nine months ended September 30, 20172022, compared to the same period in 2016 and is2021, mainly attributabledue to (i) proceeds we received from a January 2017 divestituredecrease in acquisitions of oil and natural gas properties, and (ii)offset by a decrease in contributions made to Medallion. The year-over-yearproceeds from the sale of capital assets and (ii) inflationary pressures and an increase in totalnon-operated capital expenditures forrelated to oil and natural gas properties.
The following table presents incurred capital expenditures, on an accrual basis, in the acquisition, exploration and development of oil and natural gas properties, midstream service assetswith asset retirement obligations included in evaluated property acquisition costs and other fixed assets was substantially offset by cashdevelopment costs, for the periods presented:

 Three months ended September 30,Nine months ended September 30,
(in thousands)2022202120222021
Property acquisition costs:   
Evaluated$3,515  $745,240 $8,295 $745,240 
Unevaluated179 127,505 3,470 127,505 
Exploration costs4,343 8,143 18,700 27,413 
Development costs130,961 127,031 420,468 279,032 
Total oil and natural gas properties incurred capital expenditures(1)
$138,998 $1,007,919 $450,933 $1,179,190 

outflow for 2016 acquisitions of(1)Total oil and natural gas properties. See Note 3 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of the January 2017 divestiture and the 2016 acquisitions.
Our net cash used in investing activities for the periods presented is summarized 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 quarter of 2017, our board of directors approved an increase to the 2017properties incurred capital expenditure budget of $100.0 million which represents service cost inflation, additional completion optimization testing 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.expenditures includes certain employee-related costs.
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
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Table of Content
and prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash 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, 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, our2022, $284.1 million of net cash was used in financing activities compared to $233.3 million of net cash that was provided by financing activities wasfor the resultsame period in 2021. In 2022, we began executing our strategy to return cash to shareholders through redemption of our senior secured notes and repurchasing our equity, which consisted of extinguishment of debt on our senior unsecured notes of $182.3 million and share repurchases of $26.6 million during the nine months ended September 30, 2022. Other notable 2022 activity included (i) borrowings on our Senior Secured Credit Facility partially offset by (i)of $335.0 million, (ii) payments on our Senior Secured Credit Facility (ii) the purchase of treasury$400.0 million and (iii) stock to satisfy employees'exchanged for tax withholding upon vesting of their stock-based compensation awards$7.4 million. For further discussion of our financing activities related to debt instruments and (iii) payments for debt issuance costs as a result of entering into the Fifth Amendedshare repurchases, see Notes 4 and Restated Credit Agreement5, respectively, to our Senior Secured Credit Facility. The aforementioned increaseunaudited consolidated financial statements included elsewhere in the purchasethis Quarterly Report.
Sources 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 Liquidity
Senior Secured Credit Facility and proceeds from our July 2016 Equity Offering and May 2016 Equity Offering, partially offset by payments on our Senior Secured Credit Facility.

Our net cash provided by 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 our2022, the Senior Secured Credit Facility, and the indentures governing our senior unsecured notes.
As of September 30, 2017, we had $1.5 billion in debt outstanding, $845.0 million available for borrowings under our Senior Secured Credit Facility and $20.8 million in cashwhich matures on hand for total available liquidity of $865.8 million. On October 30, 2017, we used a portion of the proceeds from the Medallion Sale to repay borrowings outstanding under our 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.
As of October 31, 2017, we had $1.3 billion in debt outstanding, $1.0 billion available for borrowings under our Senior Secured Credit Facility and $735.0 million in cash 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 FacilityJuly 16, 2025, had a maximum credit amount of $2.0 billion, a borrowing base and an aggregate elected commitment each of $1.25 billion and $1.0 billion, respectively, with a $40.0 million balance 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.5.379%. 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 December 31, 2021, we had a $44.1 million letter of credit outstanding under the Senior Secured Credit Facility. There were no outstanding letters of credit as of September 30, 2017.2022. The Senior Secured Credit Facility is fully and unconditionally guaranteed by LMS and GCM.

On August 30, 2022, we entered into the Ninth Amendment to the Senior Secured Credit Facility. The Ninth Amendment, among other things, added additional capacity to making repurchases of the Company's common stock and clarified the conditions to making redemptions of the Company's debt.
On November 1, 2022, we entered into the Tenth Amendment to our Senior unsecured notes. Secured Credit Facility. The following table presents principal amountsTenth Amendment, among other things, (i) increases the borrowing base from $1.25 billion to $1.3 billion, (ii) permits additional senior note buybacks and applicable interest rates for our outstanding senior unsecured notes asother restricted payments, subject to certain conditions; and (iii) makes technical changes to permit us to potentially incur term loans, subject to terms to be agreed with lenders making such term loans, in addition to revolving loans, in each case, subject to the terms of September 30, 2017:
the Tenth Amendment and the Senior Secured Credit Facility.
(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
  
Refer toSee Notes 4 16.b and 16.c of15to 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.
ObligationsJanuary 2025 Notes, January 2028 Notes and commitmentsJuly 2029 Notes
AsThe following table presents principal amounts and applicable interest rates for our outstanding January 2025 Notes, January 2028 Notes and July 2029 Notes as of September 30, 2017, our contractual obligations included our March 2023 Notes, January 2022 Notes, May 2022 Notes, Senior Secured Credit Facility, drilling contract commitments, firm sale and transportation commitments, derivative deferred premiums, asset retirement obligations and office and equipment leases. From December 31, 2016 to2022:
(in millions, except for interest rates)PrincipalInterest rate
January 2025 Notes$529.5 9.500 %
January 2028 Notes326.8 10.125 %
July 2029 Notes298.2 7.750 %
Total senior unsecured notes$1,154.5 
36

Table of Content
During the nine months ended September 30, 2017, the material changes in our contractual obligations included (i) an increase2022, we repurchased a total of $85.0$184.5 million in outstanding borrowings on our Senior Secured Credit Facility, (ii) a decreaseaggregate principal amount of $71.6 million in our 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, July 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,notes. See Note 4 7, 8, 11, 16.b and 16.c to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additionalfurther discussion of these repurchases.
Supplemental Guarantor information
As of September 30, 2022, $1.2 billion of our contractual obligations.senior unsecured notes remained outstanding. 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, January 2028 Notes and July 2029 Notes.
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.
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.
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, thisFurthermore, these non-GAAP measure should be considered in conjunction with net income or loss and other performancefinancial measures prepared in accordance with GAAP, such as operating income or loss or cash flow from operating activities. Adjusted EBITDA should not be considered in isolation or as a substitute for GAAP measures of liquidity or financial performance, but rather should be considered in conjunction with GAAP measures, such as net income or loss, operating income or loss or anycash flows from operating activities.
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 incurred capital expenditures, excluding non-budgeted acquisition costs. 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 GAAPrelated factors. There are significant limitations to the use of Free Cash Flow as a measure of liquidity or financial performance.performance, including the lack of comparability due to the different methods of calculating Free Cash Flow reported by different companies.

37

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 September 30,Nine months ended September 30,
(in thousands)2022202120222021
Net cash provided by operating activities$182,615 $97,674 $720,702 $287,112 
Less:
Change in current assets and liabilities, net(1,812)(3,142)101,583 27,106 
Change in noncurrent assets and liabilities, net(7,034)(16,715)(13,247)(24,505)
Cash flows from operating activities before changes in operating assets and liabilities, net191,461 117,531 632,366 284,511 
Less incurred capital expenditures, excluding non-budgeted acquisition costs:
Oil and natural gas properties(1)
135,304 135,174 439,168 306,445 
Midstream service assets(1)
506 567 1,232 2,422 
Other fixed assets4,290 1,685 8,562 3,229 
Total incurred capital expenditures, excluding non-budgeted acquisition costs140,100 137,426 448,962 312,096 
Free Cash Flow (non-GAAP)$51,361 $(19,895)$183,404 $(27,585)

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

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 for derivatives, interest expense, write-off of debt issuance costs, gains or losses on disposal of assets, mark-to-market on derivatives, premiums paid or received for commodity derivatives that matured during the period, accretion expense, 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.


38

The following table presents a reconciliation of net income (loss) (GAAP) to Adjusted EBITDA (non-GAAP):
  Three months ended September 30,
Nine months ended September 30,
(in thousands) 2017
2016
2017
2016
Net income (loss) $11,027

$9,485

$140,413

$(242,318)
Plus:    
 

 
Depletion, depreciation and amortization 41,212

35,158

113,327

110,813
Impairment expense






162,027
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:    





(Gain) loss on derivatives, net
27,441

(6,850)
(38,127)
43,783
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)
Interest expense 23,697

23,077

69,590

70,294
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

(1)
Proportionate Adjusted EBITDA of Medallion, our equity method investee, is calculated as follows:
for the periods presented:
  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
 Three months ended September 30,Nine months ended September 30,
(in thousands)2022202120222021
Net income (loss)$337,523 $136,832 $513,288 $(71,268)
Plus:
Share-settled equity-based compensation, net1,638 1,811 6,295 5,609 
Depletion, depreciation and amortization74,928 62,678 226,555 140,763 
Impairment expense— — — 1,613 
Organizational restructuring expenses10,420 — 10,420 9,800 
Gain on disposal of assets, net(4,282)(95,201)(4,952)(93,454)
Mark-to-market on derivatives:
(Gain) loss on derivatives, net(100,748)96,240 290,995467,547 
Settlements paid for matured derivatives, net(124,289)(92,726)(423,668)(191,507)
Settlements received for contingent consideration— — 1,555 — 
Net premiums paid for commodity derivatives that matured during the period(1)
— (10,182)— (31,370)
Accretion expense954 906 2,946 3,207 
Interest expense30,967 30,406 96,251 82,222 
(Gain) loss on extinguishment of debt, net(553)— 245 — 
Income tax (benefit) expense(3,768)2,677 2,447 593 
Adjusted EBITDA (non-GAAP)$222,790 $133,441 $722,377 $323,755 
_____________________________________________________________________________
(1)Reflects net premiums paid previously or upon settlement that are attributable to derivatives settled in the respective periods presented.
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 proceduresestimates during the nine months ended September 30, 2017. For2022. See our other critical accounting policies and procedures, please see our disclosure of critical accounting policiesestimates in "Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" of the 2016our 2021 Annual Report. Additionally, see Note 2 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for a discussion
39

Table of additional accounting policies and estimates made by management.Content
Recent accounting pronouncements
See Note 15 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for information regarding recent accounting pronouncements.
Off-balance sheet arrangements
Currently, we do not have any off-balance sheet arrangements other than operating leases, drilling contracts and firm sale and transportation commitments, which are described in "—Obligations and commitments." See Note 11 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information.

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.
Commodity price exposure
Due to the inherent volatility in oil, NGL and natural gas prices and the sometimes wide pricing differentials 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 in commodity prices. We have not elected hedge accounting on these derivatives and, therefore, the gains and losses on open positions are reflected in earnings. At each period end, we estimate theoperations.
The fair valuesvalue of our derivatives using an independent third-party valuation and recognize the associated gain or loss in our unaudited consolidated statements of operations included elsewhere in this Quarterly Report.
The fair values of our derivativesopen commodity positions are largely determined by estimates of the relevant forward commodity price curves of the relevant price indices. Asindexes associated with our open derivative positions. The following table provides a sensitivity analysis of September 30, 2017,the projected incremental effect on income or loss before income taxes of a hypothetical 10% change in the relevant forward commodity price curves of the indexes associated with our derivatives would have changed our netopen commodity positions to the following amounts:
(in thousands) 10% Increase 10% Decrease
Derivatives $(17,128) $51,649
As of September 30, 2017 and December 31, 2016, the net fair values of our open derivative contracts were $15.4 million and $3.0 million, respectively. Refer to Notes 2.e, 7 and 8.a of our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional disclosures regarding our derivatives.
Interest rate risk
The expected maturity years, carrying amounts and fixed interest rates on our long-term debt as of September 30, 20172022:
(in thousands)As of September 30, 2022
Commodity derivative liability position$(40,073)
Impact of a 10% increase in forward commodity prices$(44,477)
Impact of a 10% decrease in forward commodity prices$60,771 
See Notes 8 and the Senior Secured Credit Facility's average floating interest rate for the nine months ended September 30, 2017 were as follows:
  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%
Counterparty and customer credit risk
As of September 30, 2017, our principal exposures to 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.
We have entered into International Swap Dealers Association Master Agreements ("ISDA Agreements") with each of our derivative counterparties, each of whom is also a lender in our Senior Secured Credit Facility. 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.
Refer to Note 109 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of our commodity derivatives. For additional discussion of our quantitative and qualitative disclosures regarding credit risk.about market risk, see "Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk" in our 2021 Annual Report.

Interest rate risk
Our Senior Secured Credit Facility bears interest at a floating rate and our senior unsecured notes bear interest at fixed rates. The interest rate on our Senior Secured Credit Facility as of September 30, 2022 was 5.379%. See Note 4 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of our debt. The interest rate on borrowings may be based on an alternate base rate or term secured overnight financing rate ("Term SOFR"), at our option. Interest on alternate base rate loans is equal to the sum of (a) the highest of (i) the "prime rate" (as publically announced by Wells Fargo Bank, N.A.) in effect on such day, (ii) the federal funds effective rate in effect on such day plus 0.5% and (iii) the Adjusted Term SOFR (as defined in our Senior Secured Credit Facility) for a one-month tenor in effect on such day plus 1% and (b) the applicable margin. Interest on Term SOFR loans is equal to the sum of (a)(i) the Term SOFR (as defined in our Senior Secured Credit Facility) rate for such period plus (ii) the Term SOFR Adjustment (as defined in our Senior Secured Credit Facility) of 0.1% (in the case of clause (a), subject to a floor of 0%) plus (b) the applicable margin. The applicable margin varies from 1.5% to 2.5% on alternate base rate borrowings and from 2.5% to 3.5% on Term SOFR borrowings, in each case, depending on our utilization ratio. At September 30, 2022, the applicable margin on our borrowings were 1.5% for alternate base rate borrowings and 2.5% for Term SOFR borrowings.

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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, 2017.2022. 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 controlcontrols over financial reporting (as defined in Rule 13(a)-15(f) of the Exchange Act) during the quarter ended September 30, 20172022 that have materially affected, or are reasonably likely to materially affect, our internal controlcontrols 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.

On May 3, 2017, 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. 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.
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 2016first-quarter 2022 Quarterly Report, our 2021 Annual Report. ThereReport and those set forth from time to time in our other filings with the SEC. Other than the risk factor set forth below, there have been no material changes in our risk factors from those described in the 2016our 2021 Annual Report and our first-quarter 2022 Quarterly 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.
Continuing or worsening inflationary pressures and associated changes in monetary policy have resulted in and may result in additional increases to our drilling and completions costs and costs of oilfield services, equipment, and materials, which in turn have caused and may continue to cause our capital expenditures and operating costs to rise.
The U.S. inflation rate has been steadily increasing since 2021 and into 2022. These inflationary pressures have resulted in and may result in additional increases to our drilling and completions costs and costs of oilfield services, equipment, and materials, which in turn have caused and may continue to cause our capital expenditures and operating costs to rise. Sustained levels of high inflation have likewise caused the Federal Reserve and other central banks to increase interest rates, which could have the effects of raising the cost of capital and depressing economic growth, either of which — or the combination thereof — could hurt the financial and operating results of our business.
Item 2.    RepurchasePurchases of Equity Securities
The following table summarizes purchases of common stock by Laredo for the periods presented:
Period
Total number of shares purchased(1)
Weighted-average price paid per share(2)
Total number of shares purchased as
part of publicly announced plans(3)
Maximum value that may yet be purchased under the program as of the respective period-end date(3)
July 1, 2022 - July 31, 2022102,244 $70.53 94,031 $184,283,901 
August 1, 2022 - August 31, 2022105,772 $72.18 105,772 $176,648,973 
September 1, 2022 - September 30, 202248,867 $72.07 44,884 $173,413,515 
Total256,883 244,687 
______________________________________________________________________________
(1)Includes shares that were withheld by us to satisfy tax withholding obligations that arose upon the lapse of restrictions on equity-based compensation awards.
(2)Average share price includes any commissions paid to repurchase stock.
(3)On May 31, 2022, our board of directors authorized a $200 million share repurchase program commencing on the date of such announcement and continuing through and including May 27, 2024. Share repurchases under the program may be made through a variety of methods, which may include open market purchases, including under plans complying with Rule 10b5-1 of the Exchange Act, and privately negotiated transactions. During the three months ended September 30, 2022, we repurchased 244,687 shares under this program at a cost of $17.5 million.
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.
Item 3.    Defaults Upon Senior Securities

None.
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.
Not applicable.
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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.
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 Regulation S-K is included in Exhibit 95.1 to this Quarterly Report.
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










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
 8-K3.112/22/2011
8-K3.16/1/2020
8-K3.15/26/2022
8-K3.11/6/2014
8-K3.13/4/2021
 8-A12B/A4.11/7/2014
10-Q10.48/04/2022
8-K10.18/30/2022
8-K10.111/3/2022
10-Q22.15/7/2020
 
 
 
101 The following financial information from Laredo’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2022, 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.

#    Certain schedules and exhibits to this agreement have been omitted in accordance with Item 601(a)(5) of Regulation S-K. A copy of any omitted schedule and/or exhibit will be furnished to the Securities and Exchange Commission on request.


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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: November 3, 2022By:/s/ Jason Pigott
Jason Pigott
President and Chief Executive Officer
(principal executive officer)
Date: November 3, 2022By:/s/ Bryan J. Lemmerman
Bryan J. Lemmerman
Senior Vice President and Chief Financial Officer
(principal financial officer)
Date: November 3, 2022By:/s/ Jessica R. Wren
Jessica R. Wren
Senior Director of Financial Accounting and SEC Reporting
(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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