Vital Energy, Inc. - Quarter Report: 2020 September (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2020

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 001-35380

Laredo Petroleum, Inc.

(Exact name of registrant as specified in its charter)


Delaware						45-3007926
(State or other jurisdiction of incorporation or organization)						(I.R.S. Employer Identification No.)


15 W. Sixth Street	Suite 900
Tulsa	Oklahoma	74119
(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 class	Trading symbol	Name of each exchange on which registered
Common stock, $0.01 par value per share	LPI	New 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 ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically, if any, every Interactive Data File required to be submitted 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 such files). Yes ☒ No ☐

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.


Large accelerated filer	☒	Accelerated filer	☐

Non-accelerated filer	☐	Smaller reporting company	☐


Emerging growth company	☐

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. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

Number of shares of registrant's common stock outstanding as of November 2, 2020: 12,003,806

LAREDO PETROLEUM, INC.

TABLE OF CONTENTS


			Page
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS			iii
Part I			1
Item 1. Consolidated Financial Statements (Unaudited)			1
Consolidated balance sheets as of September 30, 2020 and December 31, 2019			1
Consolidated statements of operations for the three and nine months ended September 30, 2020 and 2019			2
Consolidated statements of stockholders' equity for the three and nine months ended September 30, 2020 and 2019			3
Consolidated statements of cash flows for the nine months ended September 30, 2020 and 2019			5
Condensed notes to the consolidated financial statements:			6
Note 1—Organization and basis of presentation			6
Note 2—New accounting standards			6
Note 3—Acquisitions and divestiture			7

Note 4—Property and equipment			9
Note 5—Leases			11
Note 6—Debt			11
Note 7—Stockholders' equity			13
Note 8—Equity Incentive Plan			14
Note 9—Derivatives			20
Note 10—Fair value measurements			23
Note 11—Net loss per common share			26
Note 12—Commitments and contingencies			27

Note 13—Supplemental cash flow and non-cash information			28
Note 14—Asset retirement obligations			29
Note 15—Revenue recognition			29
Note 16—Income taxes			29
Note 17—Related parties			30
Note 18—Organizational restructurings			30
Note 19—Subsequent events			31
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations			32
Item 3. Quantitative and Qualitative Disclosures About Market Risk			56
Item 4. Controls and Procedures			59
Part II			61
Item 1. Legal Proceedings			61
Item 1A. Risk Factors			62
Item 2. Purchases of Equity Securities			63
Item 3. Defaults Upon Senior Securities			64
Item 4. Mine Safety Disclosures			65
Item 5. Other Information			66
Item 6. Exhibits			67
SIGNATURES			68

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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"). These forward-looking statements include statements, projections and estimates concerning our operations, performance, business strategy, oil, natural gas liquids ("NGL") and natural gas reserves, drilling program capital expenditures, liquidity and capital resources, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, derivative activities and potential financing. Forward-looking statements are generally accompanied by words such as "estimate," "project," "predict," "believe," "expect," "anticipate," "potential," "could," "may," "will," "foresee," "plan," "goal," "should," "intend," "pursue," "target," "continue," "suggest" or the negative thereof or other variations thereof or other words that convey the uncertainty of future events or outcomes. Forward-looking statements are not guarantees of performance. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. Among the factors that significantly impact our business and could impact our business in the future are:

•the effects, duration, government response or other implications of the outbreak and continued spread of the coronavirus ("COVID-19"), or the threat and occurrence of other epidemic or pandemic diseases;

•changes in domestic and global production, supply and demand for oil, NGL and natural gas, including the decrease in demand and oversupply of oil and natural gas as a result of the COVID-19 pandemic and actions by the Organization of the Petroleum Exporting Countries members and other oil exporting nations ("OPEC+");

•the volatility of oil, NGL and natural gas prices, including in our area of operation in the Permian Basin, and the extent and duration of price reductions and increased production by OPEC+;

•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;

•the effectiveness of our internal control over financial reporting and our ability to remediate a material weakness in our internal control over financial reporting;

•the potential impact of suspending drilling programs and completions activities or shutting in a portion of our wells, as well as costs to later restart, and co‐development considerations such as horizontal spacing, vertical spacing and parent‐child interactions on production of oil, NGL and natural gas from our wells;

•conditions of the energy industry and changes in the regulatory environment and in United States ("U.S.") or international legal, tax, political, administrative or economic conditions, including new or changes to existing laws, trade policies or regulations that restrict imports or exports from the U.S., 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 or eliminate federal income tax deductions for oil and gas exploration and development, which could be affected by the outcome of the U.S. presidential, congressional and state elections;

•the ongoing instability and uncertainty in the U.S. and international energy, financial and consumer markets that could adversely affect the liquidity available to us and our customers and the demand for commodities, including oil, NGL and natural gas;

•our ability to maintain listing on the New York Stock Exchange ("NYSE") and to prevent the decrease in market price and liquidity of our common stock;

•our ability to discover, estimate, develop and replace oil, NGL and natural gas reserves and inventory;

•capital requirements for our operations and projects;

•the long-term performance of wells that were completed using different technologies;

iii

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•the availability and costs of drilling and production equipment, supplies, labor and oil and natural gas processing and other services;

•the availability and costs of sufficient export infrastructure in the Permian Basin and U.S. Gulf Coast and gathering and processing capacity;

•our ability to continue to maintain the borrowing capacity under our Fifth Amended and Restated Senior Secured Credit Facility (as amended, the "Senior Secured Credit Facility") or access other means of obtaining capital and liquidity, especially during periods of sustained low commodity prices;

•our ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to our financial results and to successfully integrate acquired businesses, assets and properties;

•our ability to generate sufficient cash to service our indebtedness, fund our capital requirements and generate future profits;

•the impact of repurchases, if any, of securities from time to time;

•restrictions contained in our debt agreements, including our Senior Secured Credit Facility and the indentures governing our Senior Unsecured Notes (as defined below), as well as debt that could be incurred in the future;

•our ability to maintain the health and safety of, as well as recruit and retain, qualified personnel necessary to operate our business;

•the potential for pipeline and storage constraints in the Permian Basin and U.S. Gulf Coast and the possibility of future production curtailment in the State of Texas;

•the potentially insufficient refining capacity in the U.S. Gulf Coast to refine all of the light sweet crude oil being produced in the U.S., which could result in widening price discounts to world oil prices and potential shut-in of production due to lack of sufficient markets;

•risks related to the geographic concentration of our assets;

•our ability to secure or generate sufficient electricity to produce our wells without limitations;

•our ability to hedge and regulations that affect our ability to hedge;

•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;

•drilling and operating risks, including risks related to hydraulic fracturing activities,

•and those related to inclement weather impacting our ability to produce existing wells and/or drill and complete new wells over an extended period of time; and

•our ability to comply with federal, state and local regulatory requirements.

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," under "Part II, Item 1A. Risk Factors" and elsewhere in this Quarterly Report and our first-quarter and second-quarter 2020 Quarterly Reports, 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, 2019 (the "2019 Annual Report") and those set forth from time to time in our other filings with the Securities and Exchange Commission (the "SEC"). These documents are available through our website or through the SEC's Electronic Data Gathering and Analysis Retrieval system at http://www.sec.gov. In light of such risks and uncertainties, we caution you not to place undue reliance on these forward-looking statements. These forward-looking statements speak only as of the date of this Quarterly Report or, if earlier, as of the date they were made. We do not intend to, and disclaim any obligation to, update or revise any forward-looking statements unless required by securities law.

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Part I

Item 1. Consolidated Financial Statements (Unaudited)

Laredo Petroleum, Inc.

Consolidated balance sheets

(in thousands, except share data)

(Unaudited)


	September 30, 2020		December 31, 2019
Assets
Current assets:
Cash and cash equivalents	$	40,258	$	40,857
Accounts receivable, net	60,298		85,223
Derivatives	81,129		51,929




Other current assets	17,828		22,470

Total current assets	199,513		200,479
Property and equipment:
Oil and natural gas properties, full cost method:
Evaluated properties	7,773,776		7,421,799
Unevaluated properties not being depleted	83,558		142,354
Less accumulated depletion and impairment	(6,669,537)		(5,725,114)
Oil and natural gas properties, net	1,187,797		1,839,039
Midstream service assets, net	115,385		128,678
Other fixed assets, net	31,966		32,504
Property and equipment, net	1,335,148		2,000,221

Derivatives	9,117		23,387

Operating lease right-of-use assets	20,931		28,343
Other noncurrent assets, net	16,614		12,007

Total assets	$	1,581,323	$	2,264,437
Liabilities and stockholders' equity
Current liabilities:
Accounts payable and accrued liabilities	$	46,090	$	40,521

Accrued capital expenditures	25,061		36,328
Undistributed revenue and royalties	25,492		33,123


Derivatives	852		7,698


Operating lease liabilities	11,812		14,042
Other current liabilities	33,801		39,184

Total current liabilities	143,108		170,896
Long-term debt, net	1,218,947		1,170,417
Derivatives	1,657		—

Asset retirement obligations	63,425		60,691
Operating lease liabilities	11,715		17,208
Other noncurrent liabilities	959		3,351

Total liabilities	1,439,811		1,422,563
Commitments and contingencies
Stockholders' equity:
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued as of September 30, 2020 and December 31, 2019	—		—
Common stock, $0.01 par value, 22,500,000 shares authorized and 12,004,372 and 11,864,604 issued and outstanding as of September 30, 2020 and December 31, 2019, respectively (1)	120		2,373
Additional paid-in capital	2,395,487		2,385,355
Accumulated deficit	(2,254,095)		(1,545,854)

Total stockholders' equity	141,512		841,874
Total liabilities and stockholders' equity	$	1,581,323	$	2,264,437

______________________________________________________________________________

(1)Common stock shares were retroactively adjusted for the Company's 1-for-20 reverse stock split effective June 1, 2020. See Note 7.a.

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

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Laredo Petroleum, Inc.

Consolidated statements of operations

(in thousands, except per share data)

(Unaudited)


	Three months ended September 30,				Nine months ended September 30,
	2020		2019		2020		2019
Revenues:
Oil sales	$	93,329	$	141,709	$	283,412	$	430,910
NGL sales	24,935		20,522		49,721		74,954
Natural gas sales	14,198		7,520		29,357		21,126
Midstream service revenues	1,751		3,079		6,715		8,572
Sales of purchased oil	39,334		20,739		119,922		83,597
Total revenues	173,547		193,569		489,127		619,159
Costs and expenses:
Lease operating expenses	19,840		22,597		62,471		68,838
Production and ad valorem taxes	8,753		11,085		24,935		29,632
Transportation and marketing expenses	13,161		5,583		37,886		15,233
Midstream service expenses	1,073		1,191		3,058		3,401

Costs of purchased oil	42,720		20,741		138,134		83,604
General and administrative	11,473		8,852		34,694		41,427
Organizational restructuring expenses	—		5,965		4,200		16,371

Depletion, depreciation and amortization	47,015		69,099		174,891		197,900

Impairment expense	196,088		397,890		789,235		397,890
Other operating expenses	1,102		1,005		3,325		3,077
Total costs and expenses	341,225		544,008		1,272,829		857,373
Operating loss	(167,678)		(350,439)		(783,702)		(238,214)
Non-operating income (expense):
Gain (loss) on derivatives, net	(45,250)		96,684		162,049		136,713


Interest expense	(26,828)		(15,191)		(78,870)		(46,503)
Litigation settlement	—		—		—		42,500
Loss on extinguishment of debt	—		—		(13,320)		—
Gain (loss) on disposal of assets, net	(607)		1,294		(1,057)		(315)
Other income, net	533		556		608		4,269
Write-off of debt issuance costs	—		—		(1,103)		—
Total non-operating income (expense), net	(72,152)		83,343		68,307		136,664
Loss before income taxes	(239,830)		(267,096)		(715,395)		(101,550)
Income tax benefit:

Deferred	2,398		2,467		7,154		812
Total income tax benefit	2,398		2,467		7,154		812


Net loss	$	(237,432)	$	(264,629)	$	(708,241)	$	(100,738)
Net loss per common share (1):



Basic	$	(20.32)	$	(22.86)	$	(60.76)	$	(8.72)



Diluted	$	(20.32)	$	(22.86)	$	(60.76)	$	(8.72)
Weighted-average common shares outstanding(1):
Basic	11,686		11,578		11,657		11,558
Diluted	11,686		11,578		11,657		11,558

______________________________________________________________________________

(1)Net loss per common share and weighted-average common shares outstanding were retroactively adjusted for the Company's 1-for-20 reverse stock split effective June 1, 2020 as discussed in Note 7.a.

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

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Laredo Petroleum, Inc.

Consolidated statements of stockholders' equity

(in thousands)

(Unaudited)


	Common stock			Additional paid-in capital		Treasury stock (at cost)			Accumulated deficit
	Shares	Amount				Shares	Amount				Total
Balance, June 30, 2020	11,939	$	119	$	2,392,564	—	$	—	$	(2,016,663)	$	376,020


Restricted stock awards	68	1		(1)		—	—		—		—
Restricted stock forfeitures	(2)	—		—		—	—		—		—


Stock exchanged for tax withholding	—	—		—		1	(12)		—		(12)

Retirement of treasury stock	(1)	—		(12)		(1)	12		—		—

Share-settled equity-based compensation	—	—		2,936		—	—		—		2,936



Net loss	—	—		—		—	—		(237,432)		(237,432)
Balance, September 30, 2020	12,004	$	120	$	2,395,487	—	$	—	$	(2,254,095)	$	141,512

	Common stock			Additional paid-in capital		Treasury stock (at cost)			Accumulated deficit
	Shares (1)	Amount				Shares (1)	Amount				Total
Balance, June 30, 2019	11,874	$	2,375	$	2,381,450	—	$	—	$	(1,039,504)	$	1,344,321
Restricted stock awards	14	2		(2)		—	—		—		—
Restricted stock forfeitures	(4)	—		—		—	—		—		—


Stock exchanged for tax withholding	—	—		—		—	(4)		—		(4)

Retirement of treasury stock	—	—		(4)		—	4		—		—



Share-settled equity-based compensation	—	—		(436)		—	—		—		(436)
Net loss	—	—		—		—	—		(264,629)		(264,629)
Balance, September 30, 2019	11,884	$	2,377	$	2,381,008	—	$	—	$	(1,304,133)	$	1,079,252

______________________________________________________________________________

(1) Shares presented were retroactively adjusted for the Company's 1-for-20 reverse stock split effective June 1, 2020 as discussed in Note 7.a.

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

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Laredo Petroleum, Inc.

Consolidated statements of stockholders' equity

(in thousands)

(Unaudited)


	Common stock			Additional paid-in capital		Treasury stock (at cost)			Accumulated deficit
	Shares (1)	Amount				Shares (1)	Amount				Total
Balance, December 31, 2019	11,865	$	2,373	$	2,385,355	—	$	—	$	(1,545,854)	$	841,874

Reverse stock split	—	(2,277)		2,277		—	—		—		—
Restricted stock awards(2)	220	31		(31)		—	—		—		—
Restricted stock forfeitures(2)	(46)	(2)		2		—	—		—		—


Stock exchanged for tax withholding	—	—		—		35	(774)		—		(774)

Retirement of treasury stock(2)	(35)	(5)		(769)		(35)	774		—		—

Share-settled equity-based compensation	—	—		8,653		—	—		—		8,653



Net loss	—	—		—		—	—		(708,241)		(708,241)
Balance, September 30, 2020	12,004	$	120	$	2,395,487	—	$	—	$	(2,254,095)	$	141,512

	Common stock			Additional paid-in capital		Treasury stock (at cost)			Accumulated deficit
	Shares (1)	Amount				Shares (1)	Amount				Total
Balance, December 31, 2018	11,697	$	2,339	$	2,375,286	—	$	—	$	(1,203,395)	$	1,174,230

Restricted stock awards	367	73		(73)		—	—		—		—
Restricted stock forfeitures	(145)	(28)		28		—	—		—		—


Stock exchanged for tax withholding	—	—		—		35	(2,650)		—		(2,650)
Stock exchanged for cost of exercise of stock options	—	—		—		1	(76)		—		(76)
Retirement of treasury stock	(36)	(7)		(2,719)		(36)	2,726		—		—
Exercise of stock options	1	—		76		—	—		—		76


Share-settled equity-based compensation	—	—		8,410		—	—		—		8,410
Net loss	—	—		—		—	—		(100,738)		(100,738)
Balance, September 30, 2019	11,884	$	2,377	$	2,381,008	—	$	—	$	(1,304,133)	$	1,079,252

______________________________________________________________________________

(1)Shares presented were retroactively adjusted for the Company's 1-for-20 reverse stock split effective June 1, 2020 as discussed in Note 7.a.

(2)The amounts presented for common stock and additional paid-in capital include (i) unadjusted amounts for the period January 1, 2020 to May 31, 2020 and (ii) adjusted amounts for the period June 1, 2020 to September 30, 2020. See the "Reverse stock split" line item for the retroactive adjustment for the life-to-date activity through May 31, 2020.

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

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Laredo Petroleum, Inc.

Consolidated statements of cash flows

(in thousands)

(Unaudited)


	Nine months ended September 30,
	2020		2019
Cash flows from operating activities:
Net loss	$	(708,241)	$	(100,738)
Adjustments to reconcile net loss to net cash provided by operating activities:
Share-settled equity-based compensation, net	6,111		5,244
Depletion, depreciation and amortization	174,891		197,900
Impairment expense	789,235		397,890


Mark-to-market on derivatives:
Gain on derivatives, net	(162,049)		(136,713)
Settlements received for matured derivatives, net	186,435		48,827
Settlements received (paid) for early-terminated commodity derivatives, net	6,340		(5,409)

Premiums paid for commodity derivatives	(51,070)		(7,664)
Amortization of debt issuance costs	3,304		2,539



Amortization of operating lease right-of-use assets	10,133		9,583
Loss on extinguishment of debt	13,320		—
Deferred income tax benefit	(7,154)		(812)
Other, net	4,519		2,673
Changes in operating assets and liabilities:
Decrease in accounts receivable, net	24,925		11,778
Decrease (increase) in other current assets	4,451		(4,088)
(Increase) decrease in other noncurrent assets, net	(3,619)		2,988
Increase (decrease) in accounts payable and accrued liabilities	5,569		(15,896)
Decrease in undistributed revenue and royalties	(7,631)		(18,878)

Decrease in other current liabilities	(8,216)		(21,221)
Decrease in other noncurrent liabilities	(7,633)		(1,135)

Net cash provided by operating activities	273,620		366,868
Cash flows from investing activities:
Acquisitions of oil and natural gas properties, net	(23,563)		(2,880)
Capital expenditures:

Oil and natural gas properties	(278,277)		(368,182)
Midstream service assets	(2,517)		(6,741)
Other fixed assets	(3,024)		(1,720)


Proceeds from dispositions of capital assets, net of selling costs	1,242		6,847
Net cash used in investing activities	(306,139)		(372,676)
Cash flows from financing activities:
Borrowings on Senior Secured Credit Facility	45,000		80,000
Payments on Senior Secured Credit Facility	(185,000)		(85,000)
Issuance of January 2025 Notes and January 2028 Notes	1,000,000		—

Extinguishment of debt	(808,855)		—


Stock exchanged for tax withholding	(774)		(2,650)

Payments for debt issuance costs	(18,451)		—
Net cash provided by (used in) financing activities	31,920		(7,650)
Net decrease in cash and cash equivalents	(599)		(13,458)
Cash and cash equivalents, beginning of period	40,857		45,151
Cash and cash equivalents, end of period	$	40,258	$	31,693

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


Table of Contents			Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Note 1—Organization and basis of presentation

a. Organization

Laredo Petroleum, Inc. ("Laredo"), together with its wholly-owned subsidiaries, Laredo Midstream Services, LLC ("LMS") and Garden City Minerals, LLC ("GCM"), is an independent energy company focused on the acquisition, exploration and development of oil and natural gas properties, primarily in the Permian Basin of West Texas. 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.

b. Basis of presentation

The 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 unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). All material intercompany transactions and account balances have been eliminated in the consolidation of accounts.

The unaudited 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, 2019 is derived from audited consolidated financial statements. In the opinion of management, the unaudited consolidated financial statements reflect all necessary adjustments to present fairly the Company's financial position as of September 30, 2020, results of operations for the three and nine months ended September 30, 2020 and 2019 and cash flows for the nine months ended September 30, 2020 and 2019.

Certain disclosures have been condensed or omitted from the unaudited consolidated financial statements. Accordingly, the unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in the 2019 Annual Report.

Significant accounting policies

See Note 2 in the 2019 Annual Report for discussion of significant accounting policies.

Use of estimates in the preparation of interim unaudited consolidated financial statements

The preparation of the unaudited consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ.

For further information regarding the use of estimates and assumptions, see Note 2.b in the 2019 Annual Report and Notes 8.e and 8.f pertaining to the Company's 2020 performance unit awards and phantom unit awards, respectively.

Reclassifications

Certain amounts in the accompanying unaudited consolidated financial statements have been reclassified to conform to the 2020 presentation. These reclassifications had no impact on previously reported total assets, total liabilities, net income (loss), stockholders' equity or total operating, investing or financing cash flows.

Note 2—New accounting standards

The Company considers 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 yet adopted and meaningful to disclose as of September 30, 2020.

On January 1, 2020, the Company adopted ASU 2016-13 to Topic 326, Financial Instruments—Credit Losses, that requires an allowance for expected credit losses to be recorded against newly recognized financial assets measured at an amortized cost


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basis. The measurement of expected credit losses is based on relevant information about past events, including historical experience, current conditions and reasonable and supportable forecasts that affect the collectability of the reported amount. The Company has included these factors in its analysis and determined there was minimal impact to the unaudited consolidated financial statements for the three and nine months ended September 30, 2020.

Note 3—Acquisitions and divestiture

a. 2020 Asset acquisitions and divestiture

On April 30, 2020, the Company closed an acquisition of 180 net acres in Howard County, Texas for a total purchase price of $0.6 million. The acquisition also provides for one or more potential contingent payments to be paid by the Company if the arithmetic average of the monthly settlement West Texas Intermediate ("WTI") NYMEX prices exceed certain thresholds for the contingency period beginning on January 1, 2021 and ending on the earlier of December 31, 2022 or the date the counterparty has received the maximum consideration of $1.2 million. The fair value of this contingent consideration was $0.2 million as of the acquisition date, which was recorded as part of the basis in the oil and natural gas properties acquired and as a contingent consideration derivative liability. See Note 10.a for the fair value of the contingent consideration as of September 30, 2020.

On February 4, 2020, the Company closed a transaction for $22.5 million acquiring 1,180 net acres and divesting 80 net acres in Howard County, Texas.

All transaction costs for the asset acquisitions were capitalized and were included in "Oil and natural gas properties" on the consolidated balance sheet.

See Note 19.b for discussion of the Company's acquisition of oil and natural gas properties subsequent to September 30, 2020.

On April 9, 2020, the Company closed a divestiture of 80 net acres and working interests in two producing wells in Glasscock County, Texas for a total sales price of $0.7 million, net of customary closing and post-closing sales price adjustments. The divestiture was recorded as an adjustment to oil and natural gas properties pursuant to the rules governing full cost accounting. Effective at closing, the operations and cash flows of these oil and natural gas properties were eliminated from the ongoing operations of the Company, and the Company has no continuing involvement in the properties. This divestiture did not represent a strategic shift and has not had a major effect on the Company's future operations or financial results.

b. 2019 Acquisitions

Asset acquisitions

On December 12, 2019, the Company closed an acquisition of 7,360 net acres and 750 net royalty acres in Howard County, Texas for $131.7 million, net of customary closing and subject to customary post-closing purchase price adjustments. The acquisition also provides for a potential contingent payment, where the Company is required to pay $20.0 million if the arithmetic average of the monthly settlement WTI NYMEX prices for each consecutive calendar month for the one-year period beginning January 1, 2020 through December 31, 2020 exceeds a certain threshold. The fair value of this contingent consideration was $6.2 million as of the acquisition date, which was recorded as part of the basis in the oil and natural gas properties acquired and as a contingent consideration derivative liability. See Note 10.a for the fair value of the contingent consideration as of September 30, 2020. This acquisition was primarily financed through borrowings under the Senior Secured Credit Facility. Post-closing is expected to be finalized during the fourth quarter of 2020.

On June 20, 2019, the Company acquired 640 net acres in Reagan County, Texas for $2.9 million.

All transaction costs were capitalized and were included in "Oil and natural gas properties" on the consolidated balance sheet.

Business combination

On December 6, 2019, the Company closed a bolt-on acquisition of 4,475 contiguous net acres and working interests in 49 producing wells in western Glasscock County, Texas, which included net production of 1,400 barrels of oil equivalent ("BOE") per day at the time of acquisition, for $64.6 million, net of customary closing purchase price adjustments. This acquisition was


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financed through borrowings under the Senior Secured Credit Facility. Post-closing was finalized during the nine months ended September 30, 2020.

This acquisition was accounted for as a business combination. Accordingly, the Company conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at the estimated acquisition date fair values, while transaction costs associated with the acquisition were expensed. 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 values of evaluated and unevaluated oil and natural gas properties. The fair values of these properties were 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, 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 cash flows 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 10 in the 2019 Annual Report.

The following table reflects an aggregate of the final estimate of the fair values of the assets acquired and liabilities assumed in this business combination on December 6, 2019:


(in thousands)	Fair values of acquisition
Fair values of net assets:
Evaluated oil and natural gas properties	$	29,921
Unevaluated oil and natural gas properties	34,700
Asset retirement cost	2,728
Total assets acquired	67,349
Asset retirement obligations	(2,728)
Net assets acquired	$	64,621
Fair values of consideration paid for net assets:
Cash consideration	$	64,621

c. Exchange of unevaluated oil and natural gas properties

From time to time, the Company exchanges undeveloped acreage with third parties. The exchanges are recorded at fair value and the difference is accounted for as an adjustment of capitalized costs with no gain or loss recognized pursuant to the rules governing full cost accounting, unless such adjustment would significantly alter the relationship between capitalized costs and proved reserves of oil, NGL and natural gas.


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Note 4—Property and equipment

The following table presents the Company's property and equipment as of the dates presented:


(in thousands)	September 30, 2020		December 31, 2019
Evaluated oil and natural gas properties	$	7,773,776	$	7,421,799
Less accumulated depletion and impairment	(6,669,537)		(5,725,114)
Evaluated oil and natural gas properties, net	1,104,239		1,696,685

Unevaluated oil and natural gas properties not being depleted	83,558		142,354

Midstream service assets	182,169		180,932
Less accumulated depreciation and impairment	(66,784)		(52,254)
Midstream service assets, net	115,385		128,678

Depreciable other fixed assets	36,786		37,894
Less accumulated depreciation and amortization	(23,721)		(23,649)
Depreciable other fixed assets, net	13,065		14,245

Land	18,901		18,259

Total property and equipment, net	$	1,335,148	$	2,000,221

See Note 10.b for discussion of impairments of long-lived assets during the nine months ended September 30, 2020. See Note 6 in the 2019 Annual Report for additional discussion of the Company's property and equipment.

The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain employee-related costs, incurred for the purpose of acquiring, exploring for or developing oil and natural gas properties, are capitalized and, once evaluated, depleted on a composite unit-of-production method based on estimates of proved oil, NGL and natural gas reserves. The depletion base includes estimated future development costs and dismantlement, restoration and abandonment costs, net of estimated salvage values. Capitalized costs include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Costs, including employee-related costs, associated with production and general corporate activities are expensed in the period incurred.

The Company excludes unevaluated property acquisition costs and exploration costs from the depletion calculation until it is determined whether or not proved reserves can be assigned to the properties. The Company capitalizes a portion of its interest costs to its unevaluated properties and such costs become subject to depletion when proved reserves can be assigned to the associated properties. All items classified as unevaluated properties are assessed on a quarterly basis for possible impairment. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion.

Sales of oil and natural gas properties, whether or not being depleted currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, NGL and natural gas.


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The following table presents costs incurred in the acquisition, exploration and development of oil and natural gas properties, with asset retirement obligations included in evaluated property acquisition costs and development costs, for the periods presented:


	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2020		2019		2020		2019
Property acquisition costs:							—
Evaluated	$	—	$	—	$	7,586	$	—
Unevaluated	—		—		16,468		2,880
Exploration costs	3,479		3,480		13,563		16,101
Development costs	37,649		73,357		256,374		349,738
Total oil and natural gas properties costs incurred	$	41,128	$	76,837	$	293,991	$	368,719

The aforementioned total oil and natural gas properties costs incurred included certain employee-related costs as shown in the table below.

The following table presents capitalized employee-related costs incurred in the acquisition, exploration and development of oil and natural gas properties for the periods presented:


	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2020		2019		2020		2019
Capitalized employee-related costs	$	4,976	$	4,164	$	13,573	$	14,276

The following table presents depletion expense, which is included in "Depletion, depreciation and amortization" on the unaudited consolidated statements of operations, and depletion expense per BOE sold of evaluated oil and natural gas properties for the periods presented:


	Three months ended September 30,				Nine months ended September 30,
	2020		2019		2020		2019
Depletion expense of evaluated oil and natural gas properties	$	43,648	$	65,354	$	164,705	$	186,662
Depletion expense per BOE sold	$	5.40	$	8.67	$	6.72	$	8.56

The full cost ceiling is based principally on the estimated future net revenues from proved oil, NGL and natural gas reserves, which exclude the effect of the Company's commodity derivative transactions, discounted at 10%. The SEC guidelines require companies to use the unweighted arithmetic average first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period before differentials ("Benchmark Prices"). The Benchmark Prices are then adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead ("Realized Prices") without giving effect to the Company's commodity derivative transactions. The Realized Prices are utilized to calculate the estimated future net revenues in the full cost ceiling calculation. Significant inputs included in the calculation of discounted cash flows used in the impairment analysis include the Company's estimate of operating and development costs, anticipated production of proved reserves and other relevant data. In the event the unamortized cost of evaluated oil and natural gas properties being depleted exceeds the full cost ceiling, as defined by the SEC, the excess is expensed in the period such excess occurs. Once incurred, a write-down of oil and natural gas properties is not reversible.


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The following table presents the Benchmark Prices and the Realized Prices as of the dates presented:


	September 30, 2020		June 30, 2020		March 31, 2020		December 31, 2019		September 30, 2019
Benchmark Prices:
Oil ($/Bbl)	$	39.88	$	43.60	$	52.23	$	52.19	$	54.27
NGL ($/Bbl)(1)	$	16.95	$	16.87	$	19.36	$	21.14	$	23.93
Natural gas ($/MMBtu)	$	1.06	$	0.87	$	0.58	$	0.87	$	0.85
Realized Prices:
Oil ($/Bbl)	$	41.08	$	44.97	$	52.47	$	52.12	$	52.86
NGL ($/Bbl)	$	7.71	$	7.66	$	10.47	$	12.21	$	14.78
Natural gas ($/Mcf)	$	0.68	$	0.53	$	0.28	$	0.53	$	0.52

_____________________________________________________________________________

(1) Based on the Company's average composite NGL barrel.

The following table presents full cost ceiling impairment expense, which is included in "Impairment expense" on the unaudited consolidated statements of operations for the periods presented:


	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2020		2019		2020		2019
Full cost ceiling impairment expense	$	196,088	$	397,890	$	779,718	$	397,890

Note 5—Leases

The Company has recognized operating lease right-of-use assets and operating lease liabilities on the unaudited consolidated balance sheets for leases of commercial real estate with lease terms extending into 2027 and drilling, completions, production and other equipment leases with lease terms extending through 2025. The Company's lease costs include those that are recognized in net loss during the period as well as those that are capitalized as part of the cost of another asset.

The lease costs related to drilling, completions and production activities are reflected at the Company's net ownership, which is consistent with the principals of proportional consolidation, and lease commitments are reflected on a gross basis. As of September 30, 2020, the Company had an average working interest of 97% in Laredo-operated active productive wells in its core operating area. See Note 5 in the 2019 Annual Report for additional discussion of the Company's leases.

Note 6—Debt

a. January 2025 Notes and January 2028 Notes

On January 24, 2020, the Company completed an offer and sale (the "Offering") of $600.0 million in aggregate principal amount of 9 1/2% senior unsecured notes due 2025 (the "January 2025 Notes") and $400.0 million in aggregate principal amount of 10 1/8% senior unsecured notes due 2028 (the "January 2028 Notes"). Interest for both the January 2025 Notes and January 2028 Notes is payable semi-annually, in cash in arrears on January 15 and July 15 of each year. The first interest payment was made on July 15, 2020, and consisted of interest from closing to that date. The terms of the January 2025 Notes and January 2028 Notes include covenants, which are in addition to but different than similar covenants in the Senior Secured Credit Facility, which limit the Company's ability to incur indebtedness, make restricted payments, grant liens and dispose of assets.

The January 2025 Notes and January 2028 Notes are fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain automatic customary releases, including the sale, disposition or transfer of all of the capital stock or of all or substantially all of the assets of a subsidiary guarantor to one or more persons that are not the Company or a restricted subsidiary, exercise of legal defeasance or covenant defeasance options or satisfaction and discharge of the applicable indenture, designation of a subsidiary guarantor as a non-guarantor

restricted subsidiary or as an unrestricted subsidiary in accordance with the applicable indenture, release from guarantee under the Senior Secured Credit Facility, or liquidation or dissolution (collectively, the "Releases").


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The Company received net proceeds of $982.0 million from the Offering, after deducting underwriting discounts and commissions and estimated offering expenses. The proceeds from the Offering were used (i) to fund Tender Offers (defined below) for the Company's January 2022 Notes and March 2023 Notes (defined below), (ii) to repay the Company's January 2022 Notes and March 2023 Notes that remained outstanding after settling the Tender Offers and (iii) for general corporate purposes, including repayment of a portion of the borrowings outstanding under the Company's Senior Secured Credit Facility.

b. January 2022 Notes and March 2023 Notes

On January 23, 2014, the Company completed an offering of $450.0 million in aggregate principal amount of 5 5/8% senior unsecured notes due 2022 (the "January 2022 Notes"). The January 2022 Notes were due to mature on January 15, 2022 and bore 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 were fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain Releases.

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 were due to mature on March 15, 2023 and bore 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 were fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain Releases.

On January 6, 2020, the Company commenced cash tender offers and consent solicitations for any or all of its outstanding January 2022 Notes and March 2023 Notes (collectively, the "Tender Offers"). On January 24, 2020 and February 6, 2020, the Company settled the Tender Offers for the principal outstanding amounts of $428.9 million and $299.4 million, respectively, for consideration for tender offers and early tender premiums of $431.6 million and $304.1 million for the January 2022 Notes and March 2023 Notes, respectively, plus accrued and unpaid interest. On January 29, 2020, the Company redeemed the remaining $21.1 million of January 2022 Notes not tendered under the Tender Offers at a redemption price of 100.000% of the principal amount thereof, plus accrued and unpaid interest. On March 15, 2020, the Company redeemed the remaining $50.6 million of March 2023 Notes not tendered under the Tender Offers at a redemption price of 101.563% of the principal amount thereof, plus accrued and unpaid interest. The Company recognized a loss on extinguishment of $13.3 million related to the difference between the consideration for tender offers, early tender premiums and redemption prices and the net carrying amounts of the extinguished January 2022 Notes and March 2023 Notes.

c. Senior Secured Credit Facility

As of September 30, 2020, the Senior Secured Credit Facility, which matures on April 19, 2023, had a maximum credit amount of $2.0 billion, a borrowing base and an aggregate elected commitment of $725.0 million each, with $235.0 million outstanding and was subject to an interest rate of 2.188%. The Senior Secured Credit Facility contains both financial and non-financial covenants, all of which the Company was in compliance with 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 $80.0 million. As of September 30, 2020 and December 31, 2019, the Company had one letter of credit outstanding of $44.1 million and $14.7 million, respectively, under the Senior Secured Credit Facility. The Senior Secured Credit Facility is fully and unconditionally guaranteed by LMS and GCM. For additional information see Note 7.d in the 2019 Annual Report. See Note 19.a for discussion of the additional payment on the Senior Secured Credit Facility and the reaffirmation of the Company's borrowing base associated with the semi-annual redetermination subsequent to September 30, 2020.

The Company's measurements of Adjusted EBITDA (non-GAAP) for financial reporting as compared to compliance under its debt agreements differ.


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d. Long-term debt, net

The following table presents the Company's long-term debt and debt issuance costs, net included in "Long-term debt, net" on the unaudited consolidated balance sheets as of the dates presented:


	September 30, 2020						December 31, 2019
(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(1)	$	—	$	—	$	—	$	450,000	$	(2,034)	$	447,966
March 2023 Notes(1)	—		—		—		350,000		(2,549)		347,451
January 2025 Notes(2)	600,000		(9,424)		590,576		—		—		—
January 2028 Notes(2)	400,000		(6,629)		393,371		—		—		—
Senior Secured Credit Facility(3)	235,000		—		235,000		375,000		—		375,000
Long-term debt, net	$	1,235,000	$	(16,053)	$	1,218,947	$	1,175,000	$	(4,583)	$	1,170,417

______________________________________________________________________________

(1)During the nine months ended September 30, 2020, the Company wrote off debt issuance costs in connection with the extinguishment of the January 2022 Notes and the March 2023 Notes, which are included in "Loss on extinguishment of debt" on the unaudited consolidated statement of operations.

(2)Debt issuance costs for the January 2025 Notes and the January 2028 Notes are amortized on a straight-line basis over the respective terms of the notes.

(3)Debt issuance costs, net related to the Senior Secured Credit Facility of $2.6 million and $4.5 million as of September 30, 2020 and December 31, 2019, respectively, are reported in "Other noncurrent assets, net" on the unaudited consolidated balance sheets, and are amortized on a straight-line basis. In connection with the April 2020 reduction in borrowing base, the Company wrote off $1.1 million of debt issuance costs, which are included in "Write-off of debt issuance costs" on the unaudited consolidated statement of operations, and capitalized $0.1 million of debt issuance costs during the nine months ended September 30, 2020.

Note 7—Stockholders' equity

a. Reverse stock split and Authorized Share Reduction

On March 17, 2020, the board of directors authorized an amendment to the Company's amended and restated certificate of incorporation ("Certificate of Incorporation") to effect, at the discretion of the board of directors (i) a reverse stock split that would reduce the number of shares of outstanding common stock in accordance with a ratio to be determined by the board of directors within a range of 1-for-5 and 1-for-20 currently outstanding and (ii) a reduction of the number of authorized shares of common stock by a corresponding proportion ("Authorized Share Reduction").

On May 14, 2020, after receiving stockholder approval of the amendment to the Company's Certificate of Incorporation to effect, at the discretion of the board of directors, the reverse stock split and the Authorized Share Reduction, the board of directors approved the implementation of the reverse stock split at a ratio of 1-for-20 currently outstanding shares of common stock, and the related corresponding Authorized Share Reduction.

On June 1, 2020, the amendment to the Company's Certificate of Incorporation became effective and effected the 1-for-20 reverse stock split of the Company's issued and outstanding common stock and the related Authorized Share Reduction from 450,000,000 to 22,500,000 authorized shares, par value $0.01 per share, with authorized shares of preferred stock remaining unchanged at 50,000,000, par value $0.01 per share, for a total of 72,500,000 shares of capital stock. See Note 8 for discussion of the Laredo Petroleum, Inc. Omnibus Equity Incentive Plan (the "Equity Incentive Plan"), that proportionately reduced the number of shares that may be granted.

b. Treasury stock

Treasury stock is recorded at cost, which includes incremental direct transaction costs, and is retired upon acquisition as a result of (i) stock exchanged to satisfy tax withholding that arises upon the lapse of restrictions on share-settled equity-based awards at the awardee's election or (ii) stock exchanged for the cost of exercise of stock options at the awardee's election.


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Note 8—Equity Incentive Plan

The Equity Incentive Plan provides for the granting of incentive awards in the form of restricted stock awards, stock option awards, performance share awards, outperformance share awards, performance unit awards, phantom unit awards and other awards. On June 1, 2020, in connection with the effectiveness of the reverse stock split and Authorized Share Reduction, the board of directors approved and adopted an amendment to the Equity Incentive Plan to proportionately adjust the limitations on awards that may be granted under the Equity Incentive Plan. Following the amendment, an aggregate of 1,492,500 shares may be issued under the Equity Incentive Plan. See Note 7.a for additional discussion of the reverse stock split and Authorized Share Reduction.

The Company recognizes the fair value of equity-based compensation awards, expected to vest over the requisite service period, as a charge against earnings, net of amounts capitalized. The Company's restricted stock awards, stock option awards, performance share awards and outperformance share award are accounted for as equity awards and the Company's performance unit awards and phantom unit awards are accounted for as liability awards. Equity-based compensation expense is included in "General and administrative" on the unaudited consolidated statements of operations. The Company capitalizes a portion of equity-based compensation for employees who are directly involved in the acquisition, exploration or development of oil and natural gas properties into the full cost pool. Capitalized equity-based compensation is included in "Evaluated properties" on the unaudited consolidated balance sheets.

a. Restricted stock awards

All service vesting restricted stock awards are treated as issued and outstanding in the unaudited consolidated financial statements. Per the award agreement terms, if employment is terminated prior to the restriction lapse date for reasons other than death or disability, the restricted stock awards are forfeited and canceled and are no longer considered issued and outstanding. If the termination of employment is by reason of death or disability, all of the holder's restricted stock will automatically vest. Restricted stock awards granted to employees vest in a variety of schedules that mainly include (i) 33%, 33% and 34% vesting per year beginning on the first anniversary of the grant date and (ii) full vesting on the first anniversary of the grant date. Restricted stock awards granted to non-employee directors vest immediately on the grant date.

The following table reflects the restricted stock award activity for the nine months ended September 30, 2020:


(in thousands, except for weighted-average grant-date fair value)	Restricted stock awards(1)	Weighted-average grant-date fair value (per share)(1)
Outstanding as of December 31, 2019	275	$	85.89
Granted	220	$	16.95
Forfeited	(46)	$	52.97
Vested(2)	(137)	$	79.29
Outstanding as of September 30, 2020	312	$	45.03

_____________________________________________________________________________

(1)Shares and per share data have been retroactively adjusted to reflect the Company's 1-for-20 reverse stock split effective June 1, 2020, as described in Note 7.a.

(2)The aggregate intrinsic value of vested restricted stock awards for the nine months ended September 30, 2020 was $3.1 million.

The Company utilizes the closing stock price on the grant date to determine the fair value of restricted stock awards. As of September 30, 2020, unrecognized equity-based compensation related to the restricted stock awards expected to vest was $9.3 million. Such cost is expected to be recognized over a weighted-average period of 1.63 years.


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b. Stock option awards

As of September 30, 2020, the 11,362 outstanding stock option awards have a weighted-average exercise price of $257.42 per award and a weighted-average remaining contractual term of 4.25 years. The stock option awards were adjusted for the Company's 1-for-20 reverse stock split as discussed in Note 7.a. There were 5,441 cancellations and de minimis forfeitures of stock option awards during the nine months ended September 30, 2020, and there were no grants or exercises. The vested and exercisable stock option awards as of September 30, 2020 had no intrinsic value.

c. Performance share awards

Performance share awards, which the Company has determined are equity awards, are subject to a combination of market, performance and service vesting criteria. For portions of awards with market criteria, which include: (i) the relative three-year total shareholder return ("TSR") comparing the Company's shareholder return to the shareholder return of the peer group specified in each award agreement ("RTSR Performance Percentage") and (ii) the Company's absolute three-year total shareholder return ("ATSR Appreciation"), a Monte Carlo simulation prepared by an independent third party is utilized to determine the grant-date (or modification date) fair value, and the associated expense is recognized on a straight-line basis over the three-year requisite service period of the awards. For portions of awards with performance criteria, which is the Company's three-year return on average capital employed ("ROACE Percentage"), the fair value is equal to the Company's closing stock price on the grant date (or modification date), and for each reporting period, the associated expense fluctuates and is adjusted based on an estimated payout of the number of shares of common stock to be delivered on the payment date for the three-year performance period. Any shares earned under performance share awards are expected to be issued in the first quarter following the completion of the respective requisite service periods based on the achievement of certain market and performance criteria, and the payout can range from 0% to 200%.

The following table reflects the performance share award activity for the nine months ended September 30, 2020:


(in thousands, except for weighted-average grant-date fair value)	Performance share awards(1)	Weighted-average grant-date fair value (per share)1)
Outstanding as of December 31, 2019	115	$	107.05

Forfeited	(10)	$	112.37
Lapsed(2)	(8)	$	379.20
Outstanding as of September 30, 2020	97	$	84.06

______________________________________________________________________________

(1)Shares and per share data have been retroactively adjusted to reflect the Company's 1-for-20 reverse stock split effective June 1, 2020, as described in Note 7.a.

(2)The performance share awards granted on February 17, 2017 had a performance period of January 1, 2017 to December 31, 2019 and, as their market criteria were not satisfied, resulted in a TSR modifier of 0% based on the Company finishing in the 15th percentile of its peer group for relative TSR. As such, the granted units lapsed and were not converted into the Company's common stock during the three months ended March 31, 2020.


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Condensed notes to the consolidated financial statements

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The following table presents the fair values per performance share and the expense per performance share, which is the fair value per performance share adjusted for the estimated payout of the performance criteria, for the outstanding performance share awards as of September 30, 2020 for the grant dates presented:


	June 3, 2019			February 28, 2019(1)			February 16, 2018
Market Criteria:
(1/4) RTSR Factor + (1/4) ATSR Factor:
Grant-date fair value per performance share(2)	$	49.00		$	79.61		$	201.65

Expense per performance share as of September 30, 2020(2)	$	49.00		$	79.61		$	201.65
Performance Criteria:
(1/2) ROACE Factor:
Grant-date fair value per performance share(2)	$	51.80		$	69.80		$	167.20
Estimated payout for expense as of September 30, 2020	175		%	175		%	61		%
Expense per performance share as of September 30, 2020(2)(3)	$	90.65		$	122.15		$	101.99
Combined:
Grant-date fair value per performance share(2)(4)	$	50.40		$	74.71		$	184.43
Expense per performance share as of September 30, 2020(2)(5)	$	69.83		$	100.88		$	151.82

______________________________________________________________________________

(1)The fair values of the performance shares granted on February 28, 2019 are based on the May 16, 2019 modification date. See Note 8.b in the 2019 Annual Report for additional information on the award conversion.

(2)Per share data has been retroactively adjusted to reflect the Company's 1-for-20 reverse stock split effective June 1, 2020, as described in Note 7.a.

(3)As the (1/2) ROACE Factor is based on performance criteria, the expense fluctuates based on the estimated payout and is redetermined each reporting period and the life-to-date recognized expense for the respective awards is adjusted accordingly.

(4)The combined grant-date fair value per performance share is the combination of the fair value per performance share weighted for the market and performance criteria for the respective awards.

(5)The combined expense per performance share is the combination of the expense per performance share for market and performance criteria for the respective awards.

As of September 30, 2020, unrecognized equity-based compensation related to the performance share awards expected to vest was $3.7 million. Such cost is expected to be recognized over a weighted-average period of 1.34 years.

d. Outperformance share award

An outperformance share award was granted during the year ended December 31, 2019, in conjunction with the appointment of the Company's President, and is accounted for as an equity award. The award was adjusted for the Company's 1-for-20 reverse stock split as discussed in Note 7.a. If earned, the payout ranges from 0 to 50,000 shares in the Company's common stock per the vesting schedule. This award is subject to a combination of market and service vesting criteria, therefore, a Monte Carlo simulation prepared by an independent third party was utilized to determine the grant-date fair value with the associated expense recognized over the requisite service period. The payout of this award is based on the highest 50 consecutive trading day average closing stock price of the Company that occurs during the performance period that commenced on June 3, 2019 and ends on June 3, 2022 ("Final Date"). Of the earned outperformance shares, one-third of the award will vest on the Final Date, one-third will vest on the first anniversary of the Final Date and one-third will vest on the second anniversary of the Final Date, provided that the participant has been continuously employed with the Company through the applicable vesting date.

As of September 30, 2020, unrecognized equity-based compensation related to the outperformance share award expected to vest was $0.4 million. Such cost is expected to be recognized over a weighted-average period of 3.75 years.


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Condensed notes to the consolidated financial statements

(Unaudited)

e. Performance unit awards

Performance unit awards, which the Company has determined are liability awards since they are settled in cash, are subject to a combination of market, performance and service vesting criteria. For portions of awards with market criteria, which include: (i) the RTSR Performance Percentage (as defined above) and (ii) the ATSR Appreciation (as defined above), a Monte Carlo simulation prepared by an independent third party is utilized to determine the fair value, and is re-measured at each reporting period until settlement. For portions of awards with performance criteria, which is the ROACE Percentage (as defined above), the Company's closing stock price is utilized to determine the fair value and is re-measured on the last trading day of each reporting period until settlement and, additionally, the associated expense fluctuates based on an estimated payout for the three-year performance period. The expense related to the performance unit awards is recognized on a straight-line basis over the three-year requisite service period of the awards, and the life-to-date recognized expense is adjusted accordingly at each reporting period based on the quarterly fair value re-measurements and redetermination of the estimated payout for the performance criteria. Any units earned, are expected to be paid in cash during the first quarter following the completion of the requisite service period, based on the achievement of certain market and performance criteria, and the payout can range from 0% to 200%, but is capped at 100% if the ATSR Appreciation is zero or less. Per the award agreement terms, if employment is terminated prior to the restriction lapse date for reasons other than death or disability, the performance unit awards are forfeited and canceled. If the termination of employment is by reason of death or disability, and the market and performance criteria are satisfied, then the holder of the earned performance unit awards will receive a prorated payment based on the number of days the participant was employed with the Company during the performance period.

The following table reflects the performance unit award activity for the nine months ended September 30, 2020:


(in thousands)						Performance units(1)
Outstanding as of December 31, 2019(2)						—
Granted(3)						123
Forfeited						(24)

Outstanding as of September 30, 2020						99

______________________________________________________________________________

(1)Units have been retroactively adjusted to reflect the Company's 1-for-20 reverse stock split effective June 1, 2020, as described in Note 7.a.

(2)The performance unit awards granted on February 28, 2019 were originally determined to be liability awards due to the board of directors election to settle the awards in cash. These awards were converted to performance share awards during the three months ended June 30, 2019. See Note 8.b in the 2019 Annual Report for additional information on the award conversion.

(3)The amounts potentially payable in cash at the end of the requisite service period for the performance unit awards granted on March 5, 2020 will be determined based on three criteria: (i) RTSR Performance Percentage, (ii) ATSR Appreciation and (iii) ROACE Percentage. The RTSR Performance Percentage, ATSR Appreciation and ROACE Percentage will be used to identify the "RTSR Factor," the "ATSR Factor" and the "ROACE Factor," respectively, which are used to compute the "Performance Multiple" and ultimately to determine the final value of each performance unit to be paid in cash on the payment date per the award agreement, subject to withholding requirements. In computing the Performance Multiple, the RTSR Factor is given a 1/3 weight, the ATSR Factor a 1/3 weight and the ROACE Factor a 1/3 weight. These awards have a performance period of January 1, 2020 to December 31, 2022.


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Condensed notes to the consolidated financial statements

(Unaudited)

The following table presents (i) the fair values per performance unit and the assumptions used to estimate these fair values per performance unit and (ii) the expense per performance unit, which is the fair value per performance unit adjusted for the estimated payout of the performance criteria, for the outstanding performance unit awards as of September 30, 2020 for the grant date presented:


	March 5, 2020
Market criteria:
(1/3) RTSR Factor + (1/3) ATSR Factor:
Fair value assumptions:
Remaining performance period	2.26 years
Risk-free interest rate(1)	0.13		%
Dividend yield	—		%
Expected volatility(2)	119.46		%
Closing stock price on September 30, 2020	$	9.80
Fair value per performance unit as of September 30, 2020	$	11.63
Expense per performance unit as of September 30, 2020	$	11.63
Performance criteria:
(1/3) ROACE Factor:
Fair value assumptions:
Closing stock price on September 30, 2020	$	9.80
Fair value per performance unit as of September 30, 2020	$	9.80
Estimated payout for expense as of September 30, 2020	100.00		%
Expense per performance unit as of September 30, 2020(3)	$	9.80
Combined:
Fair value per performance unit as of September 30, 2020(4)	$	11.02
Expense per performance unit as of September 30, 2020(5)	$	11.02

______________________________________________________________________________

(1)The remaining performance period matched zero-coupon risk-free interest rate was derived from the U.S. Treasury constant maturities yield curve on September 30, 2020.

(2)The Company utilized its own remaining performance period matched historical volatility in order to develop the expected volatility.

(3)As the (1/3) ROACE Factor is based on performance criteria, the expense fluctuates based on the estimated payout and is redetermined each reporting period and the life-to-date recognized expense for the award is adjusted accordingly.

(4)The combined fair value per performance unit is the combination of the fair value per performance unit weighted for the market and performance criteria for the award.

(5)The combined expense per performance unit is the combination of the expense per performance unit for market and performance criteria for the award.

As of September 30, 2020, unrecognized equity-based compensation related to the performance unit awards expected to vest was $0.9 million. Such cost is expected to be recognized over a weighted-average period of 2.50 years.

f. Phantom unit awards

Phantom unit awards, which the Company has determined are liability awards, represent the holder's right to receive the cash equivalent of one share of common stock of the Company for each phantom unit as of the applicable vesting date, subject to withholding requirements. Phantom unit awards granted to employees vest 33%, 33% and 34% per year beginning on the first anniversary of the grant date. Per the award agreement terms, if employment is terminated prior to the restriction lapse date


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Condensed notes to the consolidated financial statements

(Unaudited)

for reasons other than death or disability, the phantom unit awards are forfeited and canceled. If the termination of employment is by reason of death or disability, all of the holder's phantom unit awards automatically vest.

The following table reflects the phantom unit award activity for the nine months ended September 30, 2020:


(in thousands, except for weighted-average fair value)	Phantom units(1)	Fair value as of September 30, 2020 (per unit)1)
Outstanding as of December 31, 2019	—	$	—
Granted	75	$	9.80


Outstanding as of September 30, 2020	75	$	9.80

______________________________________________________________________________

(1)Units and per unit data have been retroactively adjusted to reflect the Company's 1-for-20 reverse stock split effective June 1, 2020, as described in Note 7.a.

The Company utilizes the closing stock price on the last day of each reporting period to determine the fair value of phantom unit awards and the life-to-date recognized expense is adjusted accordingly. As of September 30, 2020, unrecognized equity-based compensation related to the phantom unit awards expected to vest was $0.6 million. Such cost is expected to be recognized over a weighted-average period of 2.50 years.

g. 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)	2020		2019		2020		2019
Equity awards:
Restricted stock awards	$	2,140	$	2,275	$	6,682	$	10,157
Performance share awards	739		(2,455)		1,777		(2,482)
Outperformance share award	44		44		131		57
Stock option awards	13		(300)		63		678
Total share-settled equity-based compensation, gross	2,936		(436)		8,653		8,410
Less amounts capitalized	(895)		(1,303)		(2,542)		(3,166)
Total share-settled equity-based compensation, net	2,041		(1,739)		6,111		5,244
Liability awards:
Phantom unit awards	29		—		140		—
Performance unit awards	18		—		208		—
Total cash-settled equity-based compensation, gross	47		—		348		—
Less amounts capitalized	(14)		—		(57)		—
Total cash-settled equity-based compensation, net	33		—		291		—
Total equity-based compensation, net	$	2,074	$	(1,739)	$	6,402	$	5,244

See Note 18 for discussion of the Company's organizational restructurings and the related equity-based compensation reversals during the nine months ended September 30, 2020 and 2019.


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Condensed notes to the consolidated financial statements

(Unaudited)

Note 9—Derivatives

The Company has three types of derivative instruments as of September 30, 2020: (i) commodity derivatives, (ii) debt interest rate derivative and (iii) contingent consideration derivatives. See Note 10.a for the fair value measurement on a recurring basis of derivatives and Note 2.f in the 2019 Annual Report for the Company's significant accounting policies for derivatives. The Company's derivatives were not designated as hedges for accounting purposes, and the Company does not enter into such instruments for speculative trading purposes. Accordingly, the changes in fair value are recognized in "Gain (loss) on derivatives, net" under "Non-operating income (expense)" on the unaudited consolidated statements of operations.

The following table summarizes components of the Company's gain (loss) on derivatives, net by type of derivative instrument for the periods presented:


	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2020		2019		2020		2019
Commodity	$	(45,219)	$	96,684	$	155,278	$	136,713
Interest rate	9		—		(329)		—
Contingent consideration	(40)		—		7,100		—
Gain (loss) on derivatives, net	$	(45,250)	$	96,684	$	162,049	$	136,713

a. Commodity

Due to the inherent volatility in oil, NGL and natural gas prices and differences in the prices of oil, NGL and natural gas between where the Company produces and where the Company sells such commodities, the Company engages in commodity derivative transactions, such as puts, swaps, collars and basis swaps to hedge price risk associated with a portion of the Company's anticipated sales volumes. By removing a portion of the price volatility associated with future sales volumes, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flows from operations. See Note 9 in the 2019 Annual Report for information on the transaction types and settlement indexes. Additionally, the Brent ICE to WTI NYMEX basis swaps are settled based on the differential between the basis swaps' fixed differential as compared to the differential between the arithmetic average of each day's index prices for the first nearby month on the pricing dates in each calculation period, for only days when both indices settle, with the index prices being (i) the ICE Brent Crude Oil Futures Contract except for the last day of trading for the applicable expiring Brent Crude Oil Futures Contract whereby the second nearby month of the Brent Crude Oil Futures Contract settlement price will be used and (ii) the NYMEX West Texas Intermediate Light Sweet Crude Oil Futures Contract.

In regards to the Company's basis swaps, when the settlement basis differential is below the fixed basis differential, the counterparty pays the Company an amount equal to the difference between the fixed basis differential and the settlement basis differential multiplied by the hedged contract volume. When the settlement basis differential is above the fixed basis differential, the Company pays the counterparty an amount equal to the difference between the settlement basis differential and the fixed basis differential multiplied by the hedged contract volume.

During the nine months ended September 30, 2020, the Company completed hedge restructurings by (i) early terminating collars and entering into new swaps and (ii) early terminating swaps, the latter of which was completed during the three months ended September 30, 2020.

The following table details the commodity derivatives that were terminated:


	Aggregate volumes (Bbl)	Floor price ($/Bbl)		Ceiling price ($/Bbl)		Contract period
WTI NYMEX - Swaps	389,180	$	60.25	$	60.25	September 2020 - December 2020
WTI NYMEX - Collars	912,500	$	45.00	$	71.00	January 2021 - December 2021


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Condensed notes to the consolidated financial statements

(Unaudited)

The following table summarizes open commodity derivative positions as of September 30, 2020, for commodity derivatives that were entered into through September 30, 2020, for the settlement periods presented:


	Remaining year 2020		Year 2021		Year 2022
Oil:





WTI NYMEX - Swaps:
Volume (Bbl)	1,509,720		—		—
Weighted-average price ($/Bbl)	$	59.35	$	—	$	—
Brent ICE:
Puts(1):
Volume (Bbl)	—		2,463,750		—
Weighted-average floor price ($/Bbl)	$	—	$	55.00	$	—


Swaps:
Volume (Bbl)	598,000		5,037,000		3,759,500
Weighted-average price ($/Bbl)	$	63.07	$	49.43	$	47.05
Collars:
Volume (Bbl)	—		584,000		—
Weighted-average floor price ($/Bbl)	$	—	$	45.00	$	—
Weighted-average ceiling price ($/Bbl)	$	—	$	59.50	$	—
Total Brent ICE:
Total volume with floor (Bbl)	598,000		8,084,750		3,759,500
Weighted-average floor price ($/Bbl)	$	63.07	$	50.80	$	47.05
Total volume with ceiling (Bbl)	598,000		5,621,000		3,759,500
Weighted-average ceiling price ($/Bbl)	$	63.07	$	50.47	$	47.05







Total oil volume with floor (Bbl)	2,107,720		8,084,750		3,759,500
Total oil volume with ceiling (Bbl)	2,107,720		5,621,000		3,759,500
Basis Swaps:









Brent ICE to WTI NYMEX - Basis Swaps
Volume (Bbl)	901,600		—		—
Weighted-average differential ($/Bbl)	$	5.09	$	—	$	—



















NGL - Mont Belvieu OPIS:
Purity Ethane - Swaps:
Volume (Bbl)	92,000		912,500		—
Weighted-average price ($/Bbl)	$	13.60	$	12.01	$	—
Non-TET Propane - Swaps:
Volume (Bbl)	312,800		730,000		—
Weighted-average price ($/Bbl)	$	26.58	$	25.52	$	—
Non-TET Normal Butane - Swaps:
Volume (Bbl)	110,400		255,500		—
Weighted-average price ($/Bbl)	$	28.69	$	27.72	$	—
Non-TET Isobutane - Swaps:
Volume (Bbl)	27,600		67,525		—
Weighted-average price ($/Bbl)	$	29.99	$	28.79	$	—
Non-TET Natural Gasoline - Swaps:
Volume (Bbl)	101,200		237,250		—
Weighted-average price ($/Bbl)	$	45.15	$	44.31	$	—

Total NGL volume (Bbl)	644,000		2,202,775		—
TABLE CONTINUES ON NEXT PAGE


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Condensed notes to the consolidated financial statements

(Unaudited)


Natural gas:



Henry Hub NYMEX - Swaps:
Volume (MMBtu)	11,897,000		42,522,500		—
Weighted-average price ($/MMBtu)	$	2.65	$	2.59	$	—









Waha Inside FERC to Henry Hub NYMEX - Basis Swaps:
Volume (MMBtu)	10,580,000		41,610,000		7,300,000
Weighted-average differential ($/MMBtu)	$	(0.82)	$	(0.55)	$	(0.53)

_____________________________________________________________________________

(1) Associated with these open positions were $50.6 million of premiums, which were paid at the respective contracts' inception during the nine months ended September 30, 2020.

b. Interest rate

Due to the inherent volatility in interest rates, the Company has entered into an interest rate derivative swap to hedge interest rate risk associated with a portion of the Company's anticipated outstanding debt under the Senior Secured Credit Facility. The Company will pay a fixed rate over the contract term for that portion. By removing a portion of the interest rate volatility associated with anticipated outstanding debt, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flows from operations.

The following table details the interest rate derivative that was entered into during the nine months ended September 30, 2020:


	Notional amount (in thousands)		Fixed rate		Contract period
LIBOR - Swap	$	100,000	0.345	%	April 16, 2020 - April 18, 2022

c. Contingent consideration

The Company's asset acquisition of oil and natural gas properties that closed on April 30, 2020 provides for potential contingent payments to be paid by the Company if the arithmetic average of the monthly settlement WTI NYMEX prices exceed certain thresholds for the contingency period beginning on January 1, 2021 and ending on the earlier of December 31, 2022 or the date the counterparty has received the maximum consideration of $1.2 million.

See Notes 3.a and 3.b for further discussion of the Company's asset acquisitions associated with potential contingent consideration payments. At each quarterly reporting period, the Company remeasures each contingent consideration with the changes in fair values recognized in earnings. See Note 10.a for the fair value of the contingent considerations as of September 30, 2020.


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Condensed notes to the consolidated financial statements

(Unaudited)

Note 10—Fair value measurements

See the beginning of Note 10 in the 2019 Annual Report for information about the fair value hierarchy levels.

a. Fair value measurement on a recurring basis

See Note 9 for further discussion of the Company's derivatives, and see Note 2.f in the 2019 Annual Report for the Company's significant accounting policies for derivatives.

Balance sheet presentation

The following tables present the Company's derivatives' three-level fair value hierarchy by (i) assets and liabilities, (ii) current and noncurrent, (iii) commodity, interest rate and contingent consideration derivatives and (iv) oil, NGL, natural gas, LIBOR and/or deferred premiums, 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, 2020
(in thousands)	Level 1		Level 2		Level 3		Total gross fair value		Amounts offset		Net fair value presented on the unaudited consolidated balance sheets
Assets:
Current:
Commodity - Oil	$	—	$	89,930	$	—	$	89,930	$	(5,072)	$	84,858
Commodity - NGL	—		10,192		—		10,192		—		10,192
Commodity - Natural gas	—		3,495		—		3,495		(17,416)		(13,921)
Commodity - Oil deferred premiums	—		—		—		—		—		—

Noncurrent:
Commodity - Oil	$	—	$	17,152	$	—	$	17,152	$	(3,819)	$	13,333
Commodity - NGL	—		2,288		—		2,288		—		2,288
Commodity - Natural gas	—		—		—		—		(6,504)		(6,504)


Liabilities:
Current:
Commodity - Oil	$	—	$	(4,868)	$	—	$	(4,868)	$	5,072	$	204
Commodity - NGL	—		—		—		—		—		—
Commodity - Natural gas	—		(17,952)		—		(17,952)		17,416		(536)
Commodity - Oil deferred premiums	—		—		—		—		—		—

Interest rate - LIBOR	—		(185)		—		(185)		—		(185)
Contingent consideration	—		(335)		—		(335)		—		(335)
Noncurrent:
Commodity - Oil	$	—	$	(3,657)	$	—	$	(3,657)	$	3,819	$	162
Commodity - NGL	—		—		—		—		—		—
Commodity - Natural gas	—		(8,063)		—		(8,063)		6,504		(1,559)


Interest rate - LIBOR	—		(120)		—		(120)		—		(120)
Contingent consideration	—		(140)		—		(140)		—		(140)
Net derivative asset (liability) positions	$	—	$	87,737	$	—	$	87,737	$	—	$	87,737


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Condensed notes to the consolidated financial statements

(Unaudited)


	December 31, 2019
(in thousands)	Level 1		Level 2		Level 3		Total gross fair value		Amounts offset		Net fair value presented on the consolidated balance sheets
Assets:
Current:
Commodity - Oil	$	—	$	11,723	$	—	$	11,723	$	(5,301)	$	6,422
Commodity - NGL	—		13,787		—		13,787		(1,297)		12,490
Commodity - Natural gas	—		33,494		—		33,494		—		33,494
Commodity - Oil deferred premiums	—		—		—		—		(477)		(477)

Noncurrent:
Commodity - Oil	$	—	$	1,577	$	—	$	1,577	$	—	$	1,577
Commodity - NGL	—		9,547		—		9,547		—		9,547
Commodity - Natural gas	—		12,263		—		12,263		—		12,263


Liabilities:
Current:
Commodity - Oil	$	—	$	(5,649)	$	—	$	(5,649)	$	5,301	$	(348)
Commodity - NGL	—		(1,297)		—		(1,297)		1,297		—
Commodity - Natural gas	—		—		—		—		—		—
Commodity - Oil deferred premiums	—		—		(477)		(477)		477		—

Interest rate - LIBOR	—		—		—		—		—		—
Contingent consideration	—		(7,350)		—		(7,350)		—		(7,350)
Noncurrent:
Commodity - Oil	$	—	$	—	$	—	$	—	$	—	$	—
Commodity - NGL	—		—		—		—		—		—
Commodity - Natural gas	—		—		—		—		—		—


Interest rate - LIBOR	—		—		—		—		—		—
Contingent consideration	—		—		—		—		—		—
Net derivative asset (liability) positions	$	—	$	68,095	$	(477)	$	67,618	$	—	$	67,618

Commodity

See Note 10.a in the 2019 Annual Report for discussion of (i) the significant Level 2 inputs associated with the calculation of discounted cash flows used in the fair value mark-to-market analysis of commodity derivatives and (ii) the Level 3 deferred premiums associated with the Company's commodity derivative contracts. These deferred premiums have settled as of September 30, 2020.

The Company reviewed the third-party specialist's valuations of commodity derivatives, including the related inputs, and analyzed changes in fair values between reporting dates.


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Condensed notes to the consolidated financial statements

(Unaudited)

The following table summarizes the changes in net assets and liabilities classified as Level 3 measurements for the periods presented:


	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2020		2019		2020		2019
Balance of Level 3 at beginning of period	$	—	$	(3,270)	$	(477)	$	(16,565)

Change in net present value of commodity derivative deferred premiums(1)	—		(14)		—		(133)


Settlements of commodity derivative deferred premiums(2)	—		1,415		477		14,829
Balance of Level 3 at end of period	$	—	$	(1,869)	$	—	$	(1,869)

____________________________________________________________________________

(1)This amount is included in "Interest expense" on the unaudited consolidated statements of operations for the three and nine months ended September 30, 2019.

(2)The amount for the nine months ended September 30, 2019 includes $7.2 million that represents the present value of deferred premiums settled upon their early termination.

Interest rate

Significant Level 2 inputs associated with the calculation of discounted cash flows used in the fair value mark-to-market analysis of the interest rate derivative include the LIBOR interest rate forward curve and a counterparty risk-adjusted discount rate generated from a compilation of data gathered by a third-party valuation specialist. The Company reviewed the third-party specialist's valuation of the interest rate derivative, including the related inputs, and analyzed changes in fair values between reporting dates.

Contingent consideration

The Company's asset acquisition of oil and natural gas properties that closed on April 30, 2020 provides for potential contingent payments to be paid by the Company. The fair value of the contingent consideration was $0.2 million as of the April 30, 2020 acquisition date, which was recorded as part of the basis in the oil and natural gas properties acquired and as a contingent consideration derivative liability. At each quarterly reporting period prior to the end of the contingency period, the Company will remeasure the contingent consideration with the changes in fair value recognized in earnings. As of September 30, 2020, the fair value of this contingent consideration was $0.5 million.

See Note 10.a in the 2019 Annual Report for discussion of the 2019 contingent consideration and for significant Level 2 inputs for the option pricing model used in the fair value mark-to-market analysis of contingent consideration derivatives. As of September 30, 2020, the fair value of this contingent consideration was zero. The Company reviewed the third-party specialist's valuations, including the related inputs, and analyzed changes in fair values between the acquisition closing and/or reporting dates.

See Notes 3.a and 3.b for further discussion of the Company's asset acquisitions associated with the potential contingent consideration payments.

b. Fair value measurement on a nonrecurring basis

See Note 2.j in the 2019 Annual Report for the Level 2 fair value hierarchy input assumptions used in estimating the net realizable value of inventory used to account for the $1.3 million impairment expense of inventory recorded during the nine months ended September 30, 2020, pertaining to line-fill and other inventories. There were no comparable impairments of inventory recorded during the nine months ended September 30, 2019.

See Note 4.a in the 2019 Annual Report for the Level 3 fair value hierarchy input assumptions used in estimating the fair values of assets acquired and liabilities assumed for the acquisition of evaluated and unevaluated oil and natural gas properties accounted for as a business combination for the year ended December 31, 2019. There were no acquisitions of evaluated and unevaluated oil and natural gas properties accounted for as business combinations for the nine months ended September 30, 2020 or 2019.


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Condensed notes to the consolidated financial statements

(Unaudited)

See Note 10.b in the 2019 Annual Report for the Level 3 fair value hierarchy input assumptions used in the fair value measurement of long-lived assets used to account for the $8.2 million impairment expense of long-lived assets recorded during the nine months ended September 30, 2020, pertaining to midstream service assets. There were no comparable impairments of long-lived assets recorded during the nine months ended September 30, 2019.

c. Items not accounted for at fair value

The carrying amounts reported on the unaudited consolidated balance sheets for cash and cash equivalents, accounts receivable, accounts payable, accrued capital expenditures, undistributed revenue and royalties and other accrued assets and liabilities approximate their fair values.

The Company has not elected to account for its debt instruments at fair value. The following table presents the carrying amounts and fair values of the Company's debt as of the dates presented:


	September 30, 2020				December 31, 2019
(in thousands)	Long-term debt		Fair value(1)		Long-term debt		Fair value(1)
January 2022 Notes	$	—	$	—	$	450,000	$	439,875

March 2023 Notes	—		—		350,000		332,500
January 2025 Notes	600,000		357,000		—		—
January 2028 Notes	400,000		229,600		—		—
Senior Secured Credit Facility	235,000		234,724		375,000		375,275
Total	$	1,235,000	$	821,324	$	1,175,000	$	1,147,650

______________________________________________________________________________

(1)The fair values of the outstanding debt on the notes were determined using the Level 1 fair value hierarchy quoted market prices for each respective instrument as of September 30, 2020 and December 31, 2019. The fair values of the outstanding debt on the Senior Secured Credit Facility were estimated utilizing the Level 2 fair value hierarchy pricing model for similar instruments as of September 30, 2020 and December 31, 2019.

Note 11—Net loss per common share

Basic and diluted net loss per common share are computed by dividing net loss by the weighted-average common shares outstanding for the period. For the three and nine months ended September 30, 2020 and 2019, the non-vested restricted stock awards, outstanding stock option awards, non-vested performance share awards and the non-vested outperformance share award were anti-dilutive due to the Company's net loss, and, therefore, were excluded from the calculation of diluted net loss per common share. See Note 8 for additional discussion of these awards.


Table of Contents			Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The following table reflects the calculations of basic and diluted (i) weighted-average common shares outstanding and (ii) net 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)	2020		2019		2020		2019


Net loss (numerator)	$	(237,432)	$	(264,629)	$	(708,241)	$	(100,738)
Weighted-average common shares outstanding (denominator)(1):
Basic	11,686		11,578		11,657		11,558




Diluted	11,686		11,578		11,657		11,558
Net loss per common share(1):



Basic	$	(20.32)	$	(22.86)	$	(60.76)	$	(8.72)




Diluted	$	(20.32)	$	(22.86)	$	(60.76)	$	(8.72)

_____________________________________________________________________________

(1)Shares and per share data have been retroactively adjusted to reflect the Company's 1-for-20 reverse stock split effective June 1, 2020, as described in Note 7.a.

Note 12—Commitments and contingencies

a. Litigation

From time to time, the Company is subject to various legal proceedings arising in the ordinary course of business, including proceedings for which the Company may not have insurance coverage. While many of these matters involve inherent uncertainty, as of the date hereof, the Company does not currently believe that any such legal proceedings will have a material adverse effect on the Company's business, financial position, results of operations or liquidity.

b. Drilling rig contract

The Company has committed to a drilling rig contract with a third party to facilitate the Company's drilling plans. This contract is for a term of multiple months and contains an early termination clause that requires the Company to potentially pay penalties to the third party should the Company cease drilling efforts. These penalties 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, 2020 or 2019. As the Company's current drilling rig contract is an operating lease with an initial term greater than 12 months, the present value of the future commitment as of September 30, 2020 related to the drilling rig contract is included in current and noncurrent operating lease liabilities on the unaudited consolidated balance sheet as of September 30, 2020. Management does not currently anticipate the early termination of this contract in 2020.

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 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. A portion of the Company's commitments is 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 was unable to satisfy this particular commitment with purchased oil, therefore, the Company expensed firm transportation payments on excess capacity of $2.2 million during the three and nine months ended September 30, 2020, which is recorded in "Transportation and marketing expenses" on the unaudited consolidated statement of operations. The Company expensed other contractual penalties related to sales commitments of $1.0 million during the nine months ended September 30, 2019, which is recorded net with oil, ngl and natural gas sales revenues on the unaudited consolidated statement of operations. The Company's estimated aggregate liability of firm transportation payments on excess capacity and other contractual penalties is $4.1 million as of September 30, 2020, and is included in "Accounts payable and accrued liabilities" on the unaudited consolidated balance sheet. Future firm sale and transportation


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Condensed notes to the consolidated financial statements

(Unaudited)

commitments of $290.6 million are determined not probable to be incurred as of September 30, 2020 and are not recorded on the unaudited consolidated balance sheet.

d. Federal and state regulations

Oil and natural gas exploration, production and related operations are subject to extensive federal and state laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry increases the cost of doing business and affects profitability. The Company believes that it is in compliance with currently applicable federal and state regulations related to oil and natural gas exploration and production, and that compliance with the current regulations will not have a material adverse impact on the financial position or results of operations of the Company. These rules and regulations are frequently amended or reinterpreted; therefore, the Company is unable to predict the future cost or impact of complying with these regulations.

e. Environmental

The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, among other things, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed in the period incurred. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. Management believes no materially significant liabilities of this nature existed as of September 30, 2020 or December 31, 2019.

Note 13—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)	2020		2019
Supplemental cash flow information:
Cash paid for interest, net of $2,290 and $640 of capitalized interest, respectively	$	73,725	$	44,144
Net cash received for income taxes(1)	$	(2,129)	$	(691)
Supplemental non-cash investing information:
Fair value of contingent consideration on acquisition date(2)	$	225	$	—
Decrease in accrued capital expenditures	$	(11,267)	$	(5,715)

Capitalized share-settled equity-based compensation	$	2,542	$	3,166
Capitalized asset retirement cost	$	1,107	$	471

______________________________________________________________________________

(1)See Note 16 for additional discussion of the Company's income taxes.

(2)See Notes 3.a and 9.c for discussion of the Company's 2020 asset acquisition of oil and natural gas properties that includes a contingent consideration. See Note 10.a for discussion of the quarterly remeasurement of the contingent consideration.

The following table presents supplemental non-cash adjustments information related to operating leases for the periods presented:


	Nine months ended September 30,
(in thousands)	2020		2019
Right-of-use assets obtained in exchange for operating lease liabilities(1)	$	2,349	$	25,972

______________________________________________________________________________

(1)See Note 5 for additional discussion of the Company's leases.


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Condensed notes to the consolidated financial statements

(Unaudited)

Note 14—Asset retirement obligations

See Note 2.l in the 2019 Annual Report for discussion of the Company's significant accounting policies for asset retirement obligations.

The following table reconciles the Company's asset retirement obligation liability associated with tangible long-lived assets for the periods presented:


	Nine months ended September 30,
(in thousands)	2020		2019
Liability at beginning of period	$	62,718	$	56,882
Liabilities added due to acquisitions, drilling, midstream service asset construction and other	1,107		471
Accretion expense (1)	3,325		3,077
Liabilities settled due to plugging and abandonment or removed due to sale	(887)		(2,405)


Liability at end of period	$	66,263	$	58,025

_____________________________________________________________________________

(1)Accretion expense is included in "Other operating expenses" on the unaudited consolidated statements of operations.

Note 15—Revenue recognition

Oil, NGL and natural gas sales and sales of purchased oil revenues are generally recognized at the point in time that control of the product is transferred to the customer. Midstream service revenues are generated through fees for products and services that need to be delivered by midstream infrastructure, including oil and liquids-rich natural gas gathering services as well as fuel for drilling and completions activities, natural gas lift and water delivery, recycling and takeaway and are recognized over time as the customer benefits from these services when provided. A more detailed summary of the underlying contracts that give rise to the Company's revenues and methods of recognition can be found in Note 13.b in the 2019 Annual Report.

Note 16—Income taxes

The Company is subject to federal and state income taxes and the Texas franchise tax. As of September 30, 2020, the Company had federal net operating loss carryforwards totaling $2.1 billion, and of this amount, $1.7 billion will begin to expire in 2026 and $354.6 million will not expire but may be limited in future periods, and state of Oklahoma net operating loss carryforwards totaling $34.6 million that will begin to expire in 2032. As of September 30, 2020, 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, 2020, the Company's ability to capitalize intangible drilling costs, rather than expensing these costs and future projections of Oklahoma sourced income. As of September 30, 2020, a total valuation allowance of $455.1 million has been recorded to offset the Company's federal and Oklahoma net deferred tax assets, resulting in a Texas net deferred tax asset of $4.7 million, which is included in "Other noncurrent assets, net" on the unaudited consolidated balance sheets.

With the passage of the Tax Cuts and Jobs Act of 2017, the Alternative Minimum Tax ("AMT") on corporations was appealed and a provision was added allowing corporations to offset future tax liabilities by the amount of AMT paid with an AMT credit carryforward. The Coronavirus Aid, Relief, and Economic Security Act, enacted March 27, 2020 ("CARES Act"), modified the opportunity for corporations to receive the AMT carryover refunds by adding in a provision where the AMT credit carryforwards do not expire and are fully refundable with the filing of the Company's 2019 consolidated tax return. The Company paid AMT in 2017, creating an AMT credit carryforward in the amount of $4.1 million, of which $2.0 million was received in 2019 and the remaining $2.1 million was received during the three months ended September 30, 2020.


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Condensed notes to the consolidated financial statements

(Unaudited)

Note 17—Related parties

a. Helmerich & Payne, Inc.

The former Chairman of the Company's board of directors, whose term on the Company's board of directors ended on May 14, 2020, is on the board of directors of Helmerich & Payne, Inc. ("H&P"). During each of the nine months ended September 30, 2020 and 2019, the Company had one drilling rig contract with H&P that is accounted for as a long-term operating lease due to its initial term of greater than 12 months, which was capitalized and included in "Operating lease right-of-use-assets" on the unaudited consolidated balance sheets. The present value of the future commitment is included in current and noncurrent operating lease liabilities on the unaudited consolidated balance sheets. Capital expenditures for oil and natural gas properties are capitalized and are included in "Evaluated oil and natural gas properties" on the unaudited consolidated balance sheets. See Note 5 for additional discussion of the Company's significant accounting policies on leases. See Note 12.b for additional discussion of the Company's drilling rig contract.

The following table presents the capital expenditures for oil and natural gas properties paid to H&P included in the unaudited consolidated statements of cash flows for the periods presented:


	Nine months ended September 30,
(in thousands)	2020		2019

Capital expenditures for oil and natural gas properties(1)	$	18,104	$	10,828

____________________________________________________________________________

(1)Amount reflected for the nine months ended September 30, 2020 is through the date of the former Chairman's expiration of term on the Company's board of directors on May 14, 2020.

b. Halliburton

Beginning in 2020, the Chairman of the Company's board of directors is on the board of directors of Halliburton Company ("Halliburton"). Halliburton provides drilling and completions services to the Company.

The following table presents the capital expenditures for oil and natural gas properties paid to Halliburton included in the unaudited consolidated statement of cash flows for the period presented:


	Nine months ended
(in thousands)	September 30, 2020

Capital expenditures for oil and natural gas properties	$	51,393

Note 18—Organizational restructurings

On June 17, 2020, the Company announced organizational changes, including a workforce reduction of 22 individuals which included a senior officer, that were implemented immediately, subject to certain administrative procedures. In light of the COVID-19 pandemic and lower oil prices, the Company’s board of directors continues to monitor and evaluate the Company’s business and strategy and to reduce costs and better position the Company for the future.

On September 27, 2019, in connection with the previously announced comprehensive succession planning process, the Company announced that, effective as of October 1, 2019, Randy A. Foutch would transition from his role as Chief Executive Officer. In connection with this transition and in recognition of his efforts as the Company's founder, Mr. Foutch entered into an agreement under which he received the following payments and benefits: (i) a "Founder's Bonus" approved by the board of directors and (ii) 18 months of COBRA employer contributions that began on October 1, 2019.

On April 2, 2019, the Company announced the retirement of two of its senior officers. Additionally, on April 8, 2019, the Company committed to a company-wide reorganization effort (the "Plan") that included a workforce reduction of 20%, which included an executive officer. The reduction in workforce was communicated to employees on April 8, 2019 and implemented immediately, subject to certain administrative procedures. The Company's board of directors approved the Plan in response to market conditions and to reduce costs and better position the Company for the future.


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Condensed notes to the consolidated financial statements

(Unaudited)

In connection with these organizational restructurings, the Company incurred one-time charges comprised of compensation, tax, professional, outplacement and insurance-related expenses. The following table reflects the aggregate of these expenses, which is recorded as "Organizational restructuring expenses" on the unaudited consolidated statements of operations, for the periods presented:


	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2020		2019		2020		2019
Organizational restructuring expenses	$	—	$	5,965	$	4,200	$	16,371

All equity-based compensation awards held by the affected employees were forfeited and the corresponding equity-based compensation was reversed. For additional information on the associated forfeiture activity for the nine months ended September 30, 2020 and 2019, see Note 8 in this Quarterly Report and Note 6.c in the third-quarter 2019 Quarterly Report, respectively. The following table reflects the aggregate of gross equity-based compensation expense reversals in connection with the Company's respective organizational restructurings, which is recorded in "General and administrative" on the unaudited consolidated statements of operations, for the periods presented:


	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2020		2019		2020		2019
Gross equity-based compensation expense reversals	$	—	$	(5,652)	$	(793)	$	(11,706)

Note 19—Subsequent events

a. Senior Secured Credit Facility

On October 19, 2020, the Company made a $15.0 million payment on the Senior Secured Credit Facility. As a result, the outstanding balance under the Senior Secured Credit Facility was $220.0 million as of November 2, 2020.

On October 22, 2020, the borrowing base of the Company's Senior Secured Credit Facility was reaffirmed at $725.0 million in association with the semi-annual redetermination process. Changes to covenants are as follows: (i) the covenant limiting Distributions was modified such that the pro forma Consolidated Total Leverage Ratio components of such covenant were reduced from not greater than 2.5 to 1.00 to not greater than 2.00 to 1.00; and (ii) the covenant limiting Redemption of Senior Notes was modified such that the pro forma Consolidated Total Leverage Ratio component of such covenant was increased from not greater than 2.50 to 1.00 to not greater than 2.75 to 1.00 (to the extent that Redemption of Senior Notes on or after October 22, 2020 do not exceed $50 million) such that the pro forma Consolidated Total Leverage Ratio component remain unchanged as to Redemption of Senior Notes in excess of such $50 million cap; and (iii) the Consolidated Total Leverage Ratio financial covenant was decreased from not greater than 4.25 to 1.00 to not greater than 4.00 to 1.00 as of the last day of any Fiscal Quarter ending on or after December 31, 2020.

All capitalized terms above have the meanings given to them in the fifth amendment to the Senior Secured Credit Facility, as applicable.

b. Acquisition of oil and natural gas properties

On October 16, 2020, the Company closed a bolt-on acquisition of 2,758 net acres, including production of 210 BOE per day, in Howard County, Texas for a total purchase price of $11.3 million, subject to customary post-closing purchase price adjustments.

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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, 2020 and 2019, 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 2019 Annual Report. The following discussion contains "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 Statement Regarding Forward-Looking 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," "we," "us," "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, primarily in the Permian Basin of 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 included the following for the periods presented and corresponding changes:


	Three months ended September 30,				2020 compared to 2019
(in thousands)	2020		2019			Change (#)		Change (%)
Oil sales volumes (MBbl)	2,311		2,560			(249)		(10)	%
Oil equivalents sales volumes (MBOE)	8,083		7,537			546		7	%
Oil, NGL and natural gas sales(1)	$	132,462	$	169,751		$	(37,289)	(22)	%
Net loss(2)	$	(237,432)	$	(264,629)		$	27,197	10	%
Free Cash Flow (a non-GAAP financial measure)(3)	$	71,117	$	48,923		$	22,194	45	%
Adjusted EBITDA (a non-GAAP financial measure)(3)	$	137,281	$	146,167		$	(8,886)	(6)	%

_____________________________________________________________________________

(1)Our oil, NGL and natural gas sales decreased as a result of a 27% decrease in average sales price per BOE and were partially offset by a 7% increase in total volumes sold.

(2)Our net loss for the three months ended September 30, 2020 and 2019 includes a non-cash full cost ceiling impairment of $196.1 million and $397.9 million, respectively.

(3)See pages 52-54 for discussions and calculations of these non-GAAP financial measures.

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	Nine months ended September 30,				2020 compared to 2019
(in thousands)	2020		2019			Change (#)		Change (%)
Oil sales volumes (MBbl)	7,809		7,865			(56)		(1)	%
Oil equivalents sales volumes (MBOE)	24,522		21,797			2,725		13	%
Oil, NGL and natural gas sales(1)	$	362,490	$	526,990		$	(164,500)	(31)	%
Net loss(2)	$	(708,241)	$	(100,738)		$	(607,503)	(603)	%
Free Cash Flow (a non-GAAP financial measure)(3)	$	(9,952)	$	37,931		$	(47,883)	(126)	%
Adjusted EBITDA (a non-GAAP financial measure)(3)	$	386,966	$	422,291		$	(35,325)	(8)	%

_____________________________________________________________________________

(1)Our oil, NGL and natural gas sales decreased as a result of a 39% decrease in average sales price per BOE and were partially offset by a 13% increase in total volumes sold.

(2)Our net loss for the nine months ended September 30, 2020 and 2019 includes non-cash full cost ceiling impairments of $779.7 million and $397.9 million, respectively.

(3)See pages 52-54 for discussions and calculations of these non-GAAP financial measures.

Recent developments

Senior Secured Credit Facility

On October 22, 2020, the borrowing base of our Senior Secured Credit Facility was reaffirmed at $725.0 million in association with the semi-annual redetermination process. In connection with this process, we entered into the fifth amendment to our Senior Secured Credit Facility. Among the more significant changes: (i) the margin applied to both Eurodollar and Adjusted Base Rate Loans and the fees charged in connection with letters of credit were increased by 0.500%, in each case, at all levels of Borrowing Base utilization; (ii) an anti-cash hoarding provision, which is subject to customary carveouts, was added, which provision will require weekly prepayments to the extent that cash and cash equivalents of the company exceed $50 million; (iii) the covenant limiting Distributions was modified such that the pro forma Consolidated Total Leverage Ratio components of such covenant were reduced from not greater than 2.5 to 1.00 to not greater than 2.00 to 1.00; and (iv) the covenant limiting Redemption of Senior Notes was modified such that the pro forma Consolidated Total Leverage Ratio component of such covenant was increased from not greater than 2.50 to 1.00 to not greater than 2.75 to 1.00 (to the extent that Redemption of Senior Notes on or after October 22, 2020 do not exceed $50 million) such that the pro forma Consolidated Total Leverage Ratio component remain unchanged as to Redemption of Senior Notes in excess of such $50 million cap; and (v) the Consolidated Total Leverage Ratio financial covenant was decreased from not greater than 4.25 to 1.00 to not greater than 4.00 to 1.00 as of the last day of any Fiscal Quarter ending on or after December 31, 2020.

All capitalized terms above have the meanings given to them in the fifth amendment to our Senior Secured Credit Facility, as applicable.

Acquisition of oil and natural gas properties

On October 16, 2020, we closed a bolt-on acquisition of 2,758 net acres, including production of 210 BOE per day, in Howard County, Texas for a total purchase price of $11.3 million.

COVID-19

In December 2019, a highly transmissible and pathogenic strain of coronavirus surfaced in China, which has and is continuing to spread throughout the world, including the U.S. On January 30, 2020, the World Health Organization declared the outbreak of COVID-19 a "Public Health Emergency of International Concern," and on March 11, 2020, the World Health Organization characterized the outbreak as a "pandemic". The recommended actions by federal, state and local authorities to address the pandemic have resulted in a swift and unprecedented reduction in international and U.S. economic activity which, in turn, continues to adversely affect the demand for oil and natural gas and resulted in significant volatility and disruption of the financial markets. We are not able to predict the duration or ultimate impact that COVID-19 will have on our business, financial condition and results of operations. However, we have responded to these events with thoughtful planning and are committed to maintaining safe and reliable operations. The health and safety of our employees, suppliers, customers and business partners continue to be a top priority. Our policies to promote social distancing, both in the office and at field

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locations, remain in effect. Additionally, the majority of our non-field based employees successfully transitioned to working from home. We continue to closely monitor local infection rates and to conform to guidelines and best practices encouraged by the Centers for Disease Control and Prevention, the World Health Organization and other governmental and regulatory authorities to transition to appropriate return-to-work policies while minimizing interruptions to our operations. We do not believe that these measures have had a material effect on our workforce productivity.

On March 27, 2020, the CARES Act was enacted in response to the COVID-19 pandemic. It included provisions intended to provide relief to individuals and businesses in the form of loans and grants, and tax changes, among other provisions. At this time, we have not sought relief in the form of loans or grants from the CARES Act; however, we have benefited from the provision where the AMT credit carryforwards do not expire and are fully refundable.

Volatility in Commodity Prices

In early March 2020, concurrent with the spread of COVID-19 to the U.S. and just prior to the government actions mentioned above, members of OPEC+ proposed production cuts in an attempt to stabilize the oil market. However, OPEC+ failed to reach an agreement and some producers instead announced planned production increases, after which oil prices declined sharply. By mid-March 2020, WTI oil prices had declined to less than $25 per barrel, the lowest price since 2002. Although OPEC+ subsequently reached agreement in April 2020 on production cuts that went into effect in May 2020, oil prices continued to decline following announcement of the agreement. Further, producers in the U.S. and globally were slow to reduce oil production at a rate sufficient to match the sharp slowdown in economic activity caused by measures to control the spread of COVID-19, which resulted in an oversupply of oil that caused WTI oil prices to fall to -$37 per barrel on April 20th. Since the April 20th low, WTI oil prices have rebounded and averaged a price of $40 per barrel since July, but commodity prices continue to remain at low levels, with WTI oil prices most recently dropping to $36 per barrel at the end of October 2020, due to the continued lower demand caused by the COVID-19 pandemic and the associated macroeconomic events.

We maintain an active, multi-year commodity derivatives strategy to minimize commodity price volatility and support cash flows needed for operations. For October through December 2020, we currently have oil derivatives in place for 1.5 million barrels swapped at a weighted-average price of $59.35 WTI per barrel and 0.6 million barrels swapped at a weighted-average price of $63.07 Brent per barrel. For 2021, we currently have oil derivatives in place for 8.1 million barrels at a weighted-average floor price of $50.80 Brent per barrel. For 2022, we currently have oil derivatives in place for 3.8 million barrels swapped at a weighted-average price of $47.05 Brent per barrel.

With oil prices averaging $40, and our current oil commodity hedges in place, we were in the position to begin adding completions activity in September and expect to continue through the remainder of 2020 and additional drilling activity beginning in January of 2021. We currently expect capital expenditures for 2020 to be approximately $340 million to $350 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. Further, we will continue to utilize this slowdown as an opportunity to improve on our strong operations performance and to continue to manage expenses at the lowest and most efficient cost structure possible.

Pricing and reserves

Our results of operations are heavily influenced by oil, NGL and natural gas prices, and although prices have stabilized, they remain at low levels in fourth-quarter 2020 for oil and NGL. Oil, NGL and natural gas price fluctuations continue to be impacted by the COVID-19 pandemic and policies of OPEC+, which have generally increased supply, decreased demand, made more volatile economic and market conditions, caused transportation and storage constraints and led to a variety of additional issues on both a regional and global basis. Historically, commodity prices have experienced significant fluctuations; however, the volatility in the prices has substantially increased as a result of world developments in 2020. The duration of such developments may affect the economic viability of, and our ability to fund our drilling projects, as well as the economic valuation and economic recovery of oil, NGL and natural gas reserves.

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 9 and 10.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our commodity derivatives.

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Our reserves are reported in three streams: oil, NGL and natural gas. As discussed in Note 4 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report, the Realized Prices utilized to value our proved reserves as of September 30, 2020 and September 30, 2019, are as follows:


	September 30, 2020		September 30, 2019
Realized Prices:
Oil ($/Bbl)	$	41.08	$	52.86
NGL ($/Bbl)	$	7.71	$	14.78
Natural gas ($/Mcf)	$	0.68	$	0.52

The Realized Prices used to estimate proved reserves do not include derivative transactions. The unamortized cost of evaluated oil and natural gas properties being depleted exceeded the full cost ceiling as of March 31, 2020, June 30, 2020 and September 30, 2020 and, as such, we recorded non-cash full cost ceiling impairments of $177.2 million, $406.4 million and $196.1 million in the respective 2020 quarters. We recorded a $397.9 million non-cash full cost ceiling impairment during the three and nine months ended September 30, 2019. As more specifically addressed in "Low commodity price potential impact on our fourth-quarter 2020 full cost ceiling impairment test" below, if prices remain at or below the current levels, subject to numerous factors and inherent limitations, and all other factors remain constant, we will incur an additional significant non-cash full cost ceiling impairment in the fourth quarter of 2020 and 2021, which will have an adverse effect on our statement of operations. See Note 4 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for discussion of our full cost method of accounting.

Horizontal drilling of unconventional wells using enhanced completions techniques, including, but not limited to, hydraulic fracturing, is a relatively new process and, as such, forecasting the long-term production of such wells is inherently uncertain and subject to varying interpretations. As we receive and process geological and production data from these wells over time, we analyze such data to confirm whether previous assumptions regarding original forecasted production, inventory and reserves continue to appear accurate or require modification. While all production forecasts have elements of uncertainty over the life of the related wells, we have seen indications that the oil decline rates of tightly spaced wells may be steeper than originally anticipated. In 2019, we began drilling and completing wells at wider spacing to mitigate this effect in established acreage.

Initial production results, production decline rates, well density, completions design and operating method are examples of the numerous uncertainties and variables inherent in the estimation of proved reserves in future periods. The quantity of proved reserves is one of the many variables inherent in the calculation of depletion.

The following tables present our depletion expense for our evaluated oil and natural gas properties per BOE sold for the periods presented and corresponding changes:


	Three months ended September 30,				2020 compared to 2019
	2020		2019			Change ($)		Change (%)

Depletion expense per BOE sold	$	5.40	$	8.67		$	(3.27)	(38)	%


	Nine months ended September 30,				2020 compared to 2019
	2020		2019			Change ($)		Change (%)

Depletion expense per BOE sold	$	6.72	$	8.56		$	(1.84)	(21)	%

Low commodity price potential impact on our fourth-quarter 2020 full cost ceiling impairment test

We use the full cost method of accounting for our oil and natural gas properties, with the full cost ceiling, as defined by the SEC, based principally on the estimated future net revenues from our proved oil, NGL and natural gas reserves, which exclude the effect of our commodity derivative transactions, discounted at 10% under required SEC guidelines for pricing methodology. We review the carrying value of our oil and natural gas properties under the full cost accounting rules of the SEC on a quarterly basis. In the event the unamortized cost, or net book value, of evaluated oil and natural gas properties being depleted exceeds the full cost ceiling, the excess is expensed in the period such excess occurs. Once incurred, a write-down of evaluated oil and natural gas properties is not reversible.

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If prices remain at or below the current levels, subject to numerous factors and inherent limitations, some of which are discussed below, and all other factors remain constant, we could incur a substantial non-cash full cost ceiling impairment in fourth-quarter 2020, which will have an adverse effect on our statement of operations.

There are numerous uncertainties inherent in the estimation of proved reserves and accounting for oil and natural gas properties in future periods. In addition to unknown future commodity prices, other uncertainties include, but are not limited to (i) changes in drilling and completions costs, (ii) changes in oilfield service costs, (iii) production results, (iv) our ability, in a low price environment, to strategically drill the most economic locations in our multi-level horizontal targets, (v) the potential government imposed curtailment of production, (vi) the potential to shut-in a portion or all of our wells, (vii) income tax impacts, (viii) potential recognition of additional proved undeveloped reserves, (ix) any potential value added to our proved reserves when testing recoverability from drilling unbooked locations, (x) revisions to production curves based on additional data and (xi) the inherent significant volatility in the commodity prices for oil, NGL and natural gas.

Each of the above factors is evaluated on a quarterly basis and if there is a material change in any factor it is incorporated into our reserves estimation utilized in our quarterly accounting estimates. We use our reserve estimates to evaluate, also on a quarterly basis, the reasonableness of our resource development plans for our reported proved reserves. Changes in circumstance, including commodity pricing, economic factors and the other uncertainties described above may lead to changes in our development plans.

Set forth below is the calculation of a potential future impairment of our evaluated oil and natural gas properties for the fourth-quarter 2020. Such implied impairment should not be interpreted to be indicative of our development plan or of our actual future results. Each of the uncertainties noted above has been evaluated for material known trends to be potentially included in the estimation of possible fourth-quarter 2020 effects. Based on such review, we determined that the impact of decreased commodity prices is the only significant known variable necessary in calculating the following scenario.

Our hypothetical fourth-quarter 2020 full cost ceiling calculation has been prepared by substituting (i) $37.36 per Bbl for oil, (ii) $7.05 per Bbl for NGL and (iii) $0.55 per Mcf for natural gas (collectively, the "Pro Forma Fourth-Quarter Prices") for the respective Realized Prices as of September 30, 2020. All other inputs and assumptions have been held constant. Accordingly, this estimation strictly isolates the estimated impact of low commodity prices on the fourth-quarter 2020 Realized Prices that will be utilized in our full cost ceiling calculation. The Pro Forma Fourth-Quarter Prices use a slightly modified Realized Price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for oil, NGL and natural gas for the 10 months ended October 1, 2020 and holding the October 1, 2020 prices constant for the remaining eleventh and twelfth months of the calculation. Based solely on the substitution of the Pro Forma Fourth-Quarter Prices into our September 30, 2020 proved reserve estimates, the implied fourth-quarter 2020 impairment would be approximately $200 million.

We believe that substituting these prices into our September 30, 2020 proved reserve estimates may help provide users with an understanding of the potential impact on our fourth-quarter 2020 full cost ceiling test.

See Note 4 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for prices used to value our reserves and additional discussion of our full cost impairments for the three and nine months ended September 30, 2020.

Core area of operations

The oil and liquids-rich Permian Basin is characterized by multiple target horizons, extensive production histories, long-lived reserves, high drilling success rates and high initial production rates. As of September 30, 2020, we had assembled 130,952 net acres in the Permian Basin.

Results of operations

Revenues

Sources of our revenue

Our revenues are derived from the sale of produced oil, NGL and natural gas, the sale of purchased oil and providing midstream services to third parties, all within the continental U.S. and do not include the effects of derivatives. Our oil, NGL and natural gas revenues may vary significantly from period to period as a result of changes in volumes of production, pricing differentials and/or changes in commodity prices. Our sales of purchased oil revenue may vary due to changes in oil prices,

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pricing differentials and the amount of volumes purchased. Our midstream service revenues may fluctuate and vary due to oil throughput fees and the level of services provided to third parties for (i) integrated oil and natural gas gathering and transportation systems and related facilities, (ii) natural gas lift, fuel for drilling and completions activities and centralized compression infrastructure and (iii) water storage, recycling and transportation infrastructure. See Notes 2.o and 13.b to our consolidated financial statements in our 2019 Annual Report for additional information regarding our revenue recognition policies.

The following tables present our sources of revenue as a percentage of total revenues for the periods presented and corresponding changes:


	Three months ended September 30,				2020 compared to 2019
	2020		2019		Change (#)		Change (%)

Oil sales	54	%	73	%	(19)	%	(26)	%
NGL sales	14	%	11	%	3	%	27	%
Natural gas sales	8	%	4	%	4	%	100	%
Midstream service revenues	1	%	1	%	—	%	—	%
Sales of purchased oil	23	%	11	%	12	%	109	%
Total	100	%	100	%


	Nine months ended September 30,				2020 compared to 2019
	2020		2019		Change (#)		Change (%)

Oil sales	58	%	70	%	(12)	%	(17)	%
NGL sales	10	%	12	%	(2)	%	(17)	%
Natural gas sales	6	%	3	%	3	%	100	%
Midstream service revenues	1	%	1	%	—	%	—	%
Sales of purchased oil	25	%	14	%	11	%	79	%
Total	100	%	100	%

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Oil, NGL and natural gas sales volumes, revenues and prices

The following tables present information regarding our oil, NGL and natural gas sales volumes, sales revenues and average sales prices for the periods presented and corresponding changes:


	Three months ended September 30,			2020 compared to 2019
		2020		2019		Change (#)		Change (%)
Sales volumes:
Oil (MBbl)		2,311		2,560		(249)		(10)	%
NGL (MBbl)		2,760		2,344		416		18	%
Natural gas (MMcf)		18,072		15,790		2,282		14	%
Oil equivalents (MBOE)(1)(2)		8,083		7,537		546		7	%
Average daily oil equivalent sales volumes (BOE/D)(2)		87,857		81,921		5,936		7	%
Average daily oil sales volumes (Bbl/D)(2)		25,120		27,830		(2,710)		(10)	%
Sales revenues (in thousands):
Oil		$	93,329	$	141,709	$	(48,380)	(34)	%
NGL		24,935		20,522		4,413		22	%
Natural gas		14,198		7,520		6,678		89	%
Total oil, NGL and natural gas sales revenues		$	132,462	$	169,751	$	(37,289)	(22)	%
Average sales prices(2):
Oil ($/Bbl)(3)		$	40.38	$	55.35	$	(14.97)	(27)	%
NGL ($/Bbl)(3)		$	9.04	$	8.75	$	0.29	3	%
Natural gas ($/Mcf)(3)		$	0.79	$	0.48	$	0.31	65	%
Average sales price ($/BOE)(3)		$	16.39	$	22.52	$	(6.13)	(27)	%
Oil, with commodity derivatives ($/Bbl)(4)		$	59.93	$	56.15	$	3.78	7	%
NGL, with commodity derivatives ($/Bbl)(4)		$	10.46	$	13.43	$	(2.97)	(22)	%
Natural gas, with commodity derivatives ($/Mcf)(4)		$	0.92	$	1.01	$	(0.09)	(9)	%
Average sales price, with commodity derivatives ($/BOE)(4)		$	22.76	$	25.38	$	(2.62)	(10)	%

__________________________________________________________________________

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

(2)The numbers presented in the three months ended September 30, 2020 and 2019 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 in accordance with GAAP and an adjustment to reflect premiums incurred previously or upon settlement that are attributable to commodity derivatives that settled during the respective periods.

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	Nine months ended September 30,			2020 compared to 2019
		2020		2019		Change (#)		Change (%)
Sales volumes:
Oil (MBbl)		7,809		7,865		(56)		(1)	%
NGL (MBbl)		7,979		6,643		1,336		20	%
Natural gas (MMcf)		52,401		43,731		8,670		20	%
Oil equivalents (MBOE)(1)(2)		24,522		21,797		2,725		13	%
Average daily oil equivalent sales volumes (BOE/D)(2)		89,496		79,843		9,653		12	%
Average daily oil sales volumes (Bbl/D)(2)		28,500		28,810		(310)		(1)	%
Sales revenues (in thousands):
Oil		$	283,412	$	430,910	$	(147,498)	(34)	%
NGL		49,721		74,954		(25,233)		(34)	%
Natural gas		29,357		21,126		8,231		39	%
Total oil, NGL and natural gas sales revenues		$	362,490	$	526,990	$	(164,500)	(31)	%
Average sales prices(2):
Oil ($/Bbl)(3)		$	36.29	$	54.79	$	(18.50)	(34)	%
NGL ($/Bbl)(3)		$	6.23	$	11.28	$	(5.05)	(45)	%
Natural gas ($/Mcf)(3)		$	0.56	$	0.48	$	0.08	17	%
Average sales price ($/BOE)(3)		$	14.78	$	24.18	$	(9.40)	(39)	%
Oil, with commodity derivatives ($/Bbl)(4)		$	55.35	$	53.59	$	1.76	3	%
NGL, with commodity derivatives ($/Bbl)(4)		$	8.35	$	13.83	$	(5.48)	(40)	%
Natural gas, with commodity derivatives ($/Mcf)(4)		$	0.92	$	1.09	$	(0.17)	(16)	%
Average sales price, with commodity derivatives ($/BOE)(4)		$	22.32	$	25.75	$	(3.43)	(13)	%

_____________________________________________________________________________

(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, 2020 and 2019 columns are based on actual amounts and are not calculated using the rounded numbers presented in the table above or the table below.

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The following tables present settlements received for matured commodity derivatives and premiums paid previously or upon settlement attributable to commodity derivatives that matured during the periods utilized in our calculation of the average sales prices, with commodity derivatives, for the periods presented and corresponding changes:


	Three months ended September 30,				2020 compared to 2019
(in thousands)	2020		2019		Change ($)		Change (%)
Settlements received for matured commodity derivatives:
Oil	$	45,581	$	5,813	$	39,768	684	%
NGL	3,921		10,964		(7,043)		(64)	%
Natural gas	2,382		8,468		(6,086)		(72)	%
Total	$	51,884	$	25,245	$	26,639	106	%
Premiums paid previously or upon settlement attributable to commodity derivatives that matured during the respective period:
Oil	$	(405)	$	(3,748)	$	3,343	89	%


	Nine months ended September 30,				2020 compared to 2019
(in thousands)	2020		2019		Change ($)		Change (%)
Settlements received for matured commodity derivatives:
Oil	$	150,467	$	5,199	$	145,268	2,794	%
NGL	16,938		16,905		33		—	%
Natural gas	19,053		26,723		(7,670)		(29)	%
Total	$	186,458	$	48,827	$	137,631	282	%
Premiums paid previously or upon settlement attributable to commodity derivatives that matured during the respective period:
Oil	$	(1,682)	$	(14,589)	$	12,907	88	%

Changes in average 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, 2020 and 2019:


(in thousands)	Oil			NGL			Natural gas			Total
2019 Revenues	$	141,709		$	20,522		$	7,520		$	169,751
Effect of changes in average sales prices	(34,579)			778			5,592			(28,209)
Effect of changes in sales volumes	(13,801)			3,635			1,086			(9,080)

2020 Revenues	$	93,329		$	24,935		$	14,198		$	132,462
Change ($)	$	(48,380)		$	4,413		$	6,678		$	(37,289)
Change (%)	(34)		%	22		%	89		%	(22)		%


(in thousands)	Oil			NGL			Natural gas			Total
2019 Revenues	$	430,910		$	74,954		$	21,126		$	526,990
Effect of changes in average sales prices	(144,426)			(40,304)			4,043			(180,687)
Effect of changes in sales volumes	(3,072)			15,071			4,188			16,187

2020 Revenues	$	283,412		$	49,721		$	29,357		$	362,490
Change ($)	$	(147,498)		$	(25,233)		$	8,231		$	(164,500)
Change (%)	(34)		%	(34)		%	39		%	(31)		%

Beginning in March 2020, we experienced significant decreases in oil, NGL and natural gas sales prices related to the OPEC+ caused price collapse and COVID-19 caused demand reduction. Since then, oil, NGL and natural gas sales prices have stabilized and recovered to some degree, but are continuing to exhibit high volatility. Due to reduced completions activity earlier in the

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year as a result from the then sharp decline in commodity prices, our oil sales volumes have decreased. With oil prices currently stabilized, we have added completions activity during fourth-quarter 2020. The increases in NGL and natural gas sales volumes are related to our last wells completed prior to our reduced completions activity earlier in the year. In general, oil production declines at a faster rate than natural gas production.

Oil sales revenue. Our oil sales revenue is a function of oil production volumes sold and average oil sales prices received for those volumes. The decrease in oil sales revenue for the three months ended September 30, 2020, compared to the same period in 2019 is due to a 27% decrease in average oil sales prices and a 10% decrease in oil sales volumes. The decrease in oil sales revenue for the nine months ended September 30, 2020, compared to the same period in 2019 is due to a 34% decrease in average oil sales prices and a 1% decrease in oil sales volumes.

NGL sales revenue. Our NGL sales revenue is a function of NGL production volumes sold and average NGL sales prices received for those volumes. The increase in NGL sales revenue for the three months ended September 30, 2020, compared to the same period in 2019 is due to an 18% increase in NGL sales volumes and a 3% increase in average NGL sales prices. The decrease in NGL sales revenue for the nine months ended September 30, 2020, compared to the same period in 2019 is due to a 45% decrease in average NGL sales prices and was partially offset by a 20% increase in NGL sales volumes.

Natural gas sales revenue. Our natural gas sales revenue is a function of natural gas production volumes sold and average natural gas sales prices received for those volumes. The increase in natural gas sales revenue for the three months ended September 30, 2020, compared to the same period in 2019 is due to a 65% increase in average natural gas sales prices and a 14% increase in natural gas sales volumes. The increase in natural gas sales revenue for the nine months ended September 30, 2020, compared to the same period in 2019 is due to a 20% increase in natural gas sales volumes and a 17% increase in average natural gas sales prices.

The following tables present midstream service and sales of purchased oil revenues for the periods presented and corresponding changes:


	Three months ended September 30,				2020 compared to 2019
(in thousands)	2020		2019			Change ($)		Change (%)
Midstream service revenues	$	1,751	$	3,079		$	(1,328)	(43)	%
Sales of purchased oil	$	39,334	$	20,739		$	18,595	90	%


	Nine months ended September 30,				2020 compared to 2019
(in thousands)	2020		2019			Change ($)		Change (%)
Midstream service revenues	$	6,715	$	8,572		$	(1,857)	(22)	%
Sales of purchased oil	$	119,922	$	83,597		$	36,325	43	%

Midstream service revenues. Our midstream service revenues decreased for the three and nine months ended September 30, 2020 compared to the same periods in 2019. These revenues fluctuate and will vary due to oil throughput fees and the level of services provided to third parties.

Sales of purchased oil. Sales of purchased oil revenues are a function of the volumes and prices of purchased oil sold to customers and are offset by the volumes and costs of purchased oil. We are a firm shipper on both the Bridgetex and Gray Oak pipelines, the latter of which we began shipment on during fourth-quarter 2019, and we utilize purchased oil to fulfill portions of our commitments. We anticipate continuing this practice in the future.

We enter into purchase transactions with third parties and separate sale transactions. These transactions are presented on a gross basis as we act as the principal in the transaction by assuming control of the commodities purchased and the responsibility to deliver the commodities sold. Revenue is recognized when control transfers to the purchaser/customer at the delivery point based on the price received. The transportation costs associated with these transactions are presented as a component of costs of purchased oil. See "—Costs and expenses - Costs of purchased oil."

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Costs and expenses

The following tables present information regarding costs and expenses and selected average costs and expenses per BOE sold for the periods presented and corresponding changes:


	Three months ended September 30,				2020 compared to 2019
(in thousands except for per BOE sold data)	2020		2019		Change ($)		Change (%)
Costs and expenses:
Lease operating expenses	$	19,840	$	22,597	$	(2,757)	(12)	%
Production and ad valorem taxes	8,753		11,085		(2,332)		(21)	%
Transportation and marketing expenses	13,161		5,583		7,578		136	%
Midstream service expenses	1,073		1,191		(118)		(10)	%
Costs of purchased oil	42,720		20,741		21,979		106	%

General and administrative (excluding LTIP)	9,366		10,958		(1,592)		(15)	%
General and administrative (LTIP):
LTIP cash	266		—		266		100	%
LTIP non-cash	1,841		(2,106)		3,947		187	%
Organizational restructuring expenses	—		5,965		(5,965)		(100)	%

Depletion, depreciation and amortization	47,015		69,099		(22,084)		(32)	%
Impairment expense	196,088		397,890		(201,802)		(51)	%
Other operating expenses	1,102		1,005		97		10	%
Total costs and expenses	$	341,225	$	544,008	$	(202,783)	(37)	%
Selected average costs and expenses per BOE sold(1):
Lease operating expenses	$	2.45	$	3.00	$	(0.55)	(18)	%
Production and ad valorem taxes	1.08		1.47		(0.39)		(27)	%
Transportation and marketing expenses	1.63		0.74		0.89		120	%
Midstream service expenses	0.13		0.16		(0.03)		(19)	%
General and administrative (excluding LTIP)	1.16		1.46		(0.30)		(21)	%
Total selected operating expenses	$	6.45	$	6.83	$	(0.38)	(6)	%
General and administrative (LTIP):
LTIP cash	$	0.03	$	—	$	0.03	100	%
LTIP non-cash	$	0.23	$	(0.28)	$	0.51	182	%
Depletion, depreciation and amortization	$	5.82	$	9.17	$	(3.35)	(37)	%

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(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.

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	Nine months ended September 30,				2020 compared to 2019
(in thousands except for per BOE sold data)	2020		2019		Change ($)		Change (%)
Costs and expenses:
Lease operating expenses	$	62,471	$	68,838	$	(6,367)	(9)	%
Production and ad valorem taxes	24,935		29,632		(4,697)		(16)	%
Transportation and marketing expenses	37,886		15,233		22,653		149	%
Midstream service expenses	3,058		3,401		(343)		(10)	%
Costs of purchased oil	138,134		83,604		54,530		65	%

General and administrative (excluding LTIP)	28,543		37,507		(8,964)		(24)	%
General and administrative (LTIP):
LTIP cash	862		—		862		100	%
LTIP non-cash	5,289		3,920		1,369		35	%
Organizational restructuring expenses	4,200		16,371		(12,171)		(74)	%

Depletion, depreciation and amortization	174,891		197,900		(23,009)		(12)	%
Impairment expense	789,235		397,890		391,345		98	%
Other operating expenses	3,325		3,077		248		8	%
Total costs and expenses	$	1,272,829	$	857,373	$	415,456	48	%
Selected average costs and expenses per BOE sold(1):
Lease operating expenses	$	2.55	$	3.16	$	(0.61)	(19)	%
Production and ad valorem taxes	1.02		1.36		(0.34)		(25)	%
Transportation and marketing expenses	1.54		0.70		0.84		120	%
Midstream service expenses	0.12		0.16		(0.04)		(25)	%
General and administrative (excluding LTIP)	1.16		1.72		(0.56)		(33)	%
Total selected operating expenses	$	6.39	$	7.10	$	(0.71)	(10)	%
General and administrative (LTIP):
LTIP cash	$	0.04	$	—	$	0.04	100	%
LTIP non-cash	$	0.22	$	0.18	$	0.04	22	%
Depletion, depreciation and amortization	$	7.13	$	9.08	$	(1.95)	(21)	%

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(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 includes workover expenses, and LOE per BOE sold both decreased for the three and nine months ended September 30, 2020, compared to the same periods in 2019. We continue to focus on economic efficiencies associated with the usage and procurement of products and services related to LOE and decreasing failures and related workover expenses.

Production and ad valorem taxes. Production and ad valorem taxes decreased for the three and nine months ended September 30, 2020, compared to the same periods in 2019. Production taxes, which are established by federal, state or local taxing authorities, are based on and fluctuate in proportion to our oil, NGL and natural gas sales revenues. 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.

Transportation and marketing expenses. Transportation and marketing expenses increased for the three and nine months ended September 30, 2020, compared to the same periods in 2019. We recognize transportation and marketing expenses incurred for the delivery of produced oil to customers in the U.S. Gulf Coast market via the Bridgetex pipeline and the Gray Oak pipeline. We began shipment on the Gray Oak pipeline during the fourth quarter of 2019. We plan to ship the majority of our produced oil to the U.S. Gulf Coast, which we believe provides a long-term pricing advantage versus the Midland market. Additionally, firm transportation payments on excess pipeline capacity associated with transportation agreements are included in transportation and marketing expenses. During the three and nine months ended September 30, 2020, we expensed firm transportation payments on excess capacity of $2.2 million related to a transportation commitment with a certain pipeline pertaining to the gathering of our production from our established acreage that extends into 2024. See "—

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Obligations and commitments" and Note 12.c to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for information regarding our transportation commitments. Additionally, we recognized marketing expense due to negative natural gas prices in March 2020.

Midstream service expenses. Midstream service expenses decreased for the three and nine months ended September 30, 2020, compared to the same periods in 2019. Midstream service expenses are costs incurred to operate and maintain our (i) integrated oil and natural gas gathering and transportation systems and related facilities, (ii) centralized oil storage tanks, (iii) natural gas lift, fuel for drilling and completions activities and centralized compression infrastructure and (iv) water storage, recycling and transportation facilities.

Costs of purchased oil. Costs of purchased oil increased for the three and nine months ended September 30, 2020, compared to the same period in 2019 due to increased shipments on pipelines, partially offset by a decrease in oil prices. We are a firm shipper on both the Bridgetex and Gray Oak pipelines, the latter of which we began shipment on during fourth-quarter 2019, and we utilize purchased oil to fulfill portions of our commitments. While our long-haul transportation capacity on the Bridgetex pipeline and Gray Oak pipeline is expected to exceed our net production, consistent with our historic practice, we expect to continue to purchase third-party oil at the trading hubs to satisfy the deficit in our associated long-haul transportation commitments.

General and administrative ("G&A"). G&A, excluding employee compensation expense from our long-term incentive plan ("LTIP"), decreased for the three and nine months ended September 30, 2020, compared to the same periods in 2019 mainly due to decreases in employee-related costs as a result of the cumulative measures taken during both of the second quarters of 2020 and 2019 to align our cost structure with operational activity, which included workforce reductions.

LTIP cash expense increased for the three and nine months ended September 30, 2020, compared to the same periods in 2019, as these types of cash awards were not in place in 2019. LTIP non-cash expense increased for the three and nine months ended September 30, 2020, respectively, compared to the same periods in 2019. We had greater share-settled equity-based compensation expense, net reversals in 2019 due to organizational restructurings. See Notes 8 and 18 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for information regarding our equity-based compensation.

Organizational restructuring expenses. Organizational restructuring expenses are related to our workforce reductions and retirements in an effort to reduce costs and better position ourselves for the future in response to market conditions. We incurred one-time charges comprised of compensation, taxes, professional fees, outplacement and insurance-related expenses during the three months ended September 30, 2019 and during the nine months ended September 30, 2020 and 2019. As of September 30, 2020, no additional organizational restructuring expenses are expected to be incurred. See Note 18 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of the organizational restructurings.

Depletion, depreciation and amortization ("DD&A"). The following tables present the components of our DD&A for the periods presented and corresponding changes:


	Three months ended September 30,				2020 compared to 2019
(in thousands)	2020		2019		Change ($)		Change (%)
Depletion of evaluated oil and natural gas properties	$	43,648	$	65,354	$	(21,706)	(33)	%
Depreciation of midstream service assets	2,436		2,575		(139)		(5)	%
Depreciation and amortization of other fixed assets	931		1,170		(239)		(20)	%
Total DD&A	$	47,015	$	69,099	$	(22,084)	(32)	%


	Nine months ended September 30,				2020 compared to 2019
(in thousands)	2020		2019		Change ($)		Change (%)
Depletion of evaluated oil and natural gas properties	$	164,705	$	186,662	$	(21,957)	(12)	%
Depreciation of midstream service assets	7,394		7,619		(225)		(3)	%
Depreciation and amortization of other fixed assets	2,792		3,619		(827)		(23)	%
Total DD&A	$	174,891	$	197,900	$	(23,009)	(12)	%

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DD&A decreased for the three and nine months ended September 30, 2020 compared to the same periods in 2019. Depletion expense per BOE decreased by $3.27, or 38%, and by $1.84, or 22%, for the three and nine months ended September 30, 2020, respectively, compared to the same periods in 2019. Depletion expense decreased as a result of the full cost impairments incurred during fourth-quarter 2019, first-quarter 2020 and second-quarter 2020, and we expect depletion expense to further decrease in fourth-quarter 2020 due to the third-quarter 2020 impairment. For further discussion of our depletion base and depletion expense per BOE, see Note 4 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report and "—Pricing and reserves."

Impairment expense. The following table presents the components of our impairment expense for the periods presented:


	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2020		2019		2020		2019
Full cost ceiling impairment expense	$	196,088	$	397,890	$	779,718	$	397,890
Midstream service asset impairment expense	—		—		8,183		—
Line-fill and other inventories impairment expense	—		—		1,334		—
Total impairment expense	$	196,088	$	397,890	$	789,235	$	397,890

Our net book value of evaluated oil and natural gas properties exceeded the full cost ceiling as of March 31, 2020, June 30, 2020 and September 30, 2020, and, as a result, we recorded full cost ceiling impairments of $177.2 million, $406.4 million and $196.1 million in the respective 2020 quarters. We recorded a full cost ceiling impairment of $397.9 million during the three and nine months ended September 30, 2019. The full cost ceiling is based principally on the estimated future net revenues from proved oil, NGL and natural gas reserves, which exclude the effect of our commodity derivative transactions, discounted at 10%. The Realized Prices are utilized to calculate the estimated 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 expensed in the period such excess occurs. Once incurred, a write-down of oil and natural gas properties is not reversible. With the continuing volatility in commodity prices, we may incur additional significant write-downs on our evaluated oil and natural gas properties. See Note 4 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report and "—Pricing and reserves" for additional information regarding our full cost ceiling calculation.

Impairment losses are recorded on 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. All inventory is carried at the lower of cost or net realizable value ("NRV"), with cost determined using the weighted-average cost method. For additional discussion of our long-lived assets and inventories, see Note 10.b to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.

Non-operating income (expense)

The following tables presents the components of non-operating income (expense), net for the periods presented and corresponding changes:


	Three months ended September 30,				2020 compared to 2019
(in thousands)	2020		2019		Change ($)		Change (%)
Gain (loss) on derivatives, net	$	(45,250)	$	96,684	$	(141,934)	(147)	%
Interest expense	(26,828)		(15,191)		(11,637)		(77)	%


Gain (loss) on disposal of assets, net	(607)		1,294		(1,901)		(147)	%
Other income, net	533		556		(23)		(4)	%

Total non-operating income (expense), net	$	(72,152)	$	83,343	$	(155,495)	(187)	%

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	Nine months ended September 30,				2020 compared to 2019
(in thousands)	2020		2019		Change ($)		Change (%)
Gain on derivatives, net	$	162,049	$	136,713	$	25,336	19	%
Interest expense	(78,870)		(46,503)		(32,367)		(70)	%
Litigation settlement	—		42,500		(42,500)		(100)	%
Loss on extinguishment of debt	(13,320)		—		(13,320)		(100)	%
Loss on disposal of assets, net	(1,057)		(315)		(742)		(236)	%
Other income, net	608		4,269		(3,661)		(86)	%
Write-off of debt issuance costs	(1,103)		—		(1,103)		(100)	%
Total non-operating income, net	$	68,307	$	136,664	$	(68,357)	(50)	%

Gain (loss) on derivatives, net. The following tables present the changes in the components of gain (loss) on derivatives, net for the periods presented and corresponding changes:


	Three months ended September 30,				2020 compared to 2019
(in thousands)	2020		2019		Change ($)		Change (%)
Non-cash gain (loss) on derivatives, net	$	(103,430)	$	72,854	$	(176,284)	(242)	%
Settlements received for matured derivatives, net	51,840		25,245		26,595		105	%
Settlements received for early-terminated commodity derivatives, net	6,340		—		6,340		100	%
Premiums paid for commodity derivatives	—		(1,415)		1,415		100	%
Gain (loss) on derivatives, net	$	(45,250)	$	96,684	$	(141,934)	(147)	%


	Nine months ended September 30,				2020 compared to 2019
(in thousands)	2020		2019		Change ($)		Change (%)
Non-cash gain on derivatives, net	$	20,344	$	100,959	$	(80,615)	(80)	%
Settlements received for matured derivatives, net	186,435		48,827		137,608		282	%
Settlements received (paid) for early-terminated commodity derivatives, net	6,340		(5,409)		11,749		217	%
Premiums paid for commodity derivatives	(51,070)		(7,664)		(43,406)		(566)	%
Gain on derivatives, net	$	162,049	$	136,713	$	25,336	19	%

Non-cash gain (loss) on derivatives, net is the result of new, matured and early-terminated contracts, including contingent consideration derivatives for the period subsequent to the acquisition date and through the end of the contingency period, and the changing relationship between our outstanding contract prices and the future market prices in the forward curves, which we use to calculate the fair value of our derivatives. In general, if outstanding contracts are held constant, we experience gains during periods of decreasing market prices and losses during periods of increasing market prices. Settlements received for matured derivatives are based on the settlement prices of our matured derivatives compared to the prices specified in the derivative contracts. During the nine months ended September 30, 2020, we completed hedge restructurings by (i) early terminating collars and entering into new swaps and (ii) early terminating swaps, the latter of which was completed during the three months ended September 30, 2020. Additionally, we entered into 2021 puts during the nine months ended September 30, 2020 and paid $50.6 million in premiums to increase the put price received.

See Notes 9 and 10.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report and "Item 3. Quantitative and Qualitative Disclosures About Market Risk" for additional information regarding our derivatives.

Interest expense. Interest expense increased for the three and nine months ended September 30, 2020, compared to the same periods in 2019. These increases are mainly due to the issuance of our January 2025 Notes and January 2028 Notes and the extinguishment of our January 2022 Notes and March 2023 Notes, resulting in an increase in the carrying amount of long-term debt along with higher fixed interest rates. See Notes 6 and 19.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information regarding our long-term debt.

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Loss on extinguishment of debt. We recognized a loss on extinguishment of debt related to the difference between the consideration for tender offers, early tender premiums and redemption prices and the net carrying amounts of the extinguished January 2022 Notes and March 2023 Notes during the nine months ended September 30, 2020. See Note 6.b to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information regarding the extinguishment of our January 2022 Notes and March 2023 Notes.

Gain (loss) on disposal of assets, net. Gain (loss) on disposal of assets, net, fluctuates depending upon the volume of the assets disposed, their associated net book value and, in the case of a disposal by sale, the sale price. From time to time, we dispose of inventory, midstream service assets and other fixed assets.

Write-off of debt issuance costs. We wrote off $1.1 million of debt issuance costs during the nine months ended September 30, 2020 as a result of decreases in the borrowing base and aggregate elected commitment of the Senior Secured Credit Facility. There were no debt issuance costs written off during the comparable period. See Note 6.d to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of our debt issuance costs.

Income tax benefit

The following tables present income tax benefit for the periods presented and corresponding changes:


	Three months ended September 30,				2020 compared to 2019
(in thousands)	2020		2019		Change ($)		Change (%)

Deferred	$	2,398	$	2,467	$	(69)	(3)	%


	Nine months ended September 30,				2020 compared to 2019
(in thousands)	2020		2019		Change ($)		Change (%)

Deferred	$	7,154	$	812	$	6,342	781	%

We are subject to federal and state income taxes and the Texas franchise tax. The deferred income tax benefit for the periods presented is attributed to deferred Texas franchise tax. As of September 30, 2020, we determined it was more likely than not that our federal and Oklahoma net deferred tax assets were not realizable through future net income. As of September 30, 2020, a total valuation allowance of $455.1 million has been recorded to offset our federal and Oklahoma net deferred tax assets, resulting in a Texas net deferred tax asset of $4.7 million. The effective tax rate for our operations was 1% for the three and nine months ended September 30, 2020. For further discussion of our income taxes, see Note 16 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.

Liquidity and capital resources

In light of the world developments in 2020, we continue to closely monitor our capital resources and business plans. Historically, 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. While we cannot predict the duration and negative impact of COVID-19 and OPEC+ actions on the energy industry, we believe our cash flows from operations, favorable hedges and availability under our Senior Secured Credit Facility provide sufficient liquidity to manage our cash needs and contractual obligations and to fund our expected capital expenditures. Our primary operational uses of capital have been for the acquisition, exploration and development of oil and natural gas properties and infrastructure development.

We continually monitor the markets and consider which financing alternatives, including debt and equity 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 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, or combination of alternatives, if any, will depend on prevailing market conditions, our liquidity requirements,

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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 6 and 19.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.

Due to the inherent volatility in oil, NGL and natural gas prices and differences in the prices of oil, NGL and natural gas between where we produce and where we sell such commodities, we engage in commodity derivative transactions, such as puts, swaps, collars and basis swaps to hedge price risk associated with a portion of our anticipated sales volumes. Due to the inherent volatility in interest rates, we have entered into an interest rate derivative swap to hedge interest rate risk associated with a portion of our anticipated outstanding debt under the Senior Secured Credit Facility. We will pay a fixed rate over the contract term for that portion. By removing a portion of the (i) price volatility associated with future sales volumes and (ii) interest rate volatility associated with anticipated outstanding debt, we expect to mitigate, but not eliminate, the potential effects of variability in cash flows from operations. See "Part I. Item 3. Quantitative and Qualitative Disclosures About Market Risk" below.

See Notes 9.a and 9.b to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for discussion of our (i) commodity hedge restructurings during the nine months ended September 30, 2020 and corresponding summary of open commodity derivative positions as of September 30, 2020 for commodity derivatives that were entered into through September 30, 2020 and (ii) interest rate derivative, respectively.

We continually seek to maintain a financial profile that provides operational flexibility. As of September 30, 2020, we had cash and cash equivalents of $40.3 million and available capacity under the Senior Secured Credit Facility, after the reduction for outstanding letters of credit, of $445.9 million, resulting in total liquidity of $486.2 million. As of November 2, 2020, we had cash and cash equivalents of $28 million and available capacity under the Senior Secured Credit Facility, after the reduction for outstanding letters of credit, of $460.9 million, resulting in total liquidity of $488.9 million. We believe that our operating cash flows and the aforementioned liquidity sources provide us with the financial resources to manage our business needs, to implement our currently planned capital expenditure budget and, at our discretion, to fund any share repurchases, pay down, repurchase or refinance debt or adjust our planned capital expenditure budget.

Cash flows

The following table presents our cash flows for the periods presented and corresponding changes:


	Nine months ended September 30,				2020 compared to 2019
(in thousands)	2020		2019		Change ($)		Change (%)
Net cash provided by operating activities	$	273,620	$	366,868	$	(93,248)	(25)	%
Net cash used in investing activities	(306,139)		(372,676)		66,537		18	%
Net cash provided by (used in) financing activities	31,920		(7,650)		39,570		517	%
Net decrease in cash and cash equivalents	$	(599)	$	(13,458)	$	12,859	96	%

Cash flows from operating activities

Net cash provided by operating activities decreased during the nine months ended September 30, 2020, compared to the same period in 2019. Notable cash changes include (i) a decrease in total oil, NGL and natural gas sales revenues of $164.5 million, (ii) an increase of $106.0 million in net settlements received for matured and early-terminated derivatives, net of premiums paid, mainly due to decreases in commodity prices, (iii) an increase of $54.3 million due to net changes in operating assets and liabilities and (iv) a decrease in non-recurring litigation proceeds of $42.5 million. Other significant changes are increases in interest expense, costs of purchased oil partially offset by sales of purchased oil and transportation and marketing expenses. The decrease in total oil, NGL and natural gas sales revenues is due to a 39% decrease in average sales price per BOE and was partially offset by a 13% increase in total volumes sold. For additional information, see "—Results of operations."

Our operating cash flows are sensitive to a number of variables, the most significant of which are the volatility of oil, NGL and natural gas prices, mitigated to the extent of our commodity derivatives' exposure, and sales volume levels. Regional and worldwide economic activity, weather, infrastructure, transportation capacity to reach markets, costs of operations, legislation and regulations, including potential government production curtailments, and other variable factors significantly impact the prices of these commodities. Commodity prices have been most impacted by the effects of COVID-19 on demand and the effects of the OPEC+ actions, and earlier in the year, related transportation and storage constraints, particularly in the

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State of Texas, on supply. These factors are not within our control and are difficult to predict. For additional information on risks related to our business, see "Part I. Item 3. Quantitative and Qualitative Disclosures About Market Risk" and "Part II. Item 1A. Risk Factors" included elsewhere in this Quarterly Report and "Part I. Item 1A. Risk Factors" in our 2019 Annual Report.

Cash flows from investing activities

Net cash used in investing activities decreased for the nine months ended September 30, 2020, compared to the same period in 2019, mainly due to a decrease in capital expenditures for oil and natural gas properties, partially offset by an increase in acquisitions of oil and natural gas properties. See Notes 3 and 19.b to our unaudited consolidated financial statements included elsewhere in the Quarterly Report for additional discussion of our acquisitions of oil and natural gas properties.

The following table presents the components of our cash flows from investing activities for the periods presented and corresponding changes:


	Nine months ended September 30,				2020 compared to 2019
(in thousands)	2020		2019		Change ($)		Change (%)
Acquisitions of oil and natural gas properties, net	$	(23,563)	$	(2,880)	$	(20,683)	(718)	%

Capital expenditures:
Oil and natural gas properties	(278,277)		(368,182)		89,905		24	%
Midstream service assets	(2,517)		(6,741)		4,224		63	%
Other fixed assets	(3,024)		(1,720)		(1,304)		(76)	%


Proceeds from dispositions of capital assets, net of selling costs	1,242		6,847		(5,605)		(82)	%
Net cash used in investing activities	$	(306,139)	$	(372,676)	$	66,537	18	%

Expected capital expenditures

Our capital spending in 2020 has been influenced by commodity price changes, production levels and, among other factors, changes in service costs and drilling and completions efficiencies. In early 2020, the Company significantly reduced planned operational activities as commodity prices suffered from historic declines amid COVID-19 caused demand reduction and OPEC+ pricing and supply decisions, dramatically reducing expected returns on capital investments. A subsequent increase in commodity prices, paired with service cost reductions, has driven expected returns on our Howard County acreage back to levels that support a resumption of completions activity and, beginning in September 2020, the Company began operating a completions crew in Howard County. We currently expect capital expenditures for 2020 to be approximately $340 million to $350 million. We are prepared to adjust our capital expenditures further if oil, NGL and natural gas prices continue to exhibit volatility. We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted.

The following tables present the components of our costs incurred, excluding non-budgeted acquisition costs, for the periods presented and corresponding changes:


	Three months ended September 30,				2020 compared to 2019
(in thousands)	2020		2019		Change ($)		Change (%)
Oil and natural gas properties	$	41,128	$	76,837	$	(35,709)	(46)	%
Midstream service assets	1,103		1,147		(44)		(4)	%
Other fixed assets	495		999		(504)		(50)	%
Total costs incurred, excluding non-budgeted acquisition costs	$	42,726	$	78,983	$	(36,257)	(46)	%

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	Nine months ended September 30,				2020 compared to 2019
(in thousands)	2020		2019		Change ($)		Change (%)
Oil and natural gas properties	$	269,937	$	365,839	$	(95,902)	(26)	%
Midstream service assets	2,697		7,584		(4,887)		(64)	%
Other fixed assets	3,092		1,966		1,126		57	%
Total costs incurred, excluding non-budgeted acquisition costs	$	275,726	$	375,389	$	(99,663)	(27)	%

See Note 4 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information regarding our costs incurred in the exploration and development of oil and natural gas properties.

The amount, timing and allocation of capital expenditures are largely discretionary and within management's control. If oil, NGL and natural gas prices are below our acceptable levels, or costs are above our acceptable levels, we may choose to defer a portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flow. Subject to financing alternatives, we may also increase our capital expenditures significantly to take advantage of opportunities we consider to be attractive. We continually monitor and may adjust our projected capital expenditures in response to world developments, such as those we are experiencing in 2020, as well as success or lack of success in drilling activities, changes in prices, availability of financing and joint venture opportunities, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs and supplies, changes in service costs, contractual obligations, internally generated cash flow and other factors both within and outside our control.

Cash flows from financing activities

Net cash provided by (used in) financing activities increased for the nine months ended September 30, 2020, compared to the same period in 2019. Notable cash changes include the issuance of our January 2025 Notes and January 2028 Notes, partially offset by the extinguishment of our January 2022 Notes and March 2023 Notes and payments and borrowings on our Senior Secured Credit Facility. For further discussion of our financing activities related to debt instruments, see Notes 6 and 19.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.

The following table presents the components of our cash flows from financing activities for the periods presented and corresponding changes:


	Nine months ended September 30,				2020 compared to 2019
(in thousands)	2020		2019		Change ($)		Change (%)
Borrowings on Senior Secured Credit Facility	$	45,000	$	80,000	$	(35,000)	(44)	%
Payments on Senior Secured Credit Facility	(185,000)		(85,000)		(100,000)		(118)	%





Issuance of January 2025 Notes and January 2028 Notes	1,000,000		—		1,000,000		100	%
Extinguishment of debt	(808,855)		—		(808,855)		(100)	%
Stock exchanged for tax withholding	(774)		(2,650)		1,876		71	%

Payments for debt issuance costs	(18,451)		—		(18,451)		(100)	%
Net cash provided by (used in) financing activities	$	31,920	$	(7,650)	$	39,570	517	%

We are the borrower under our Senior Secured Credit Facility and a party to the indentures governing our Senior Unsecured Notes.

Senior Secured Credit Facility

As of September 30, 2020, the Senior Secured Credit Facility, which matures on April 19, 2023, had a maximum credit amount of $2.0 billion, a borrowing base and an aggregate elected commitment of $725.0 million each, with $235.0 million outstanding and was subject to an interest rate of 2.188%. The Senior Secured Credit Facility contains both financial and non-financial covenants, all of which we were in compliance with 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 $80.0 million. As of September 30, 2020 and December 31, 2019, we had one letter of credit outstanding of $44.1 million and $14.7 million, respectively, under the Senior Secured Credit Facility. The Senior Secured Credit Facility is fully and unconditionally

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guaranteed by LMS and GCM. On October 19, 2020, we made a $15.0 million payment on the Senior Secured Credit Facility. As a result, the outstanding balance under the Senior Secured Credit Facility was $220.0 million as of November 2, 2020.

On October 22, 2020, the borrowing base of our Senior Secured Credit Facility was reaffirmed at $725.0 million in association with the semi-annual redetermination process.

See Notes 6.c and 19.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of our Senior Secured Credit Facility.

January 2025 Notes and January 2028 Notes

The following table presents principal amounts and applicable interest rates for our outstanding January 2025 Notes and January 2028 Notes (together the "Senior Unsecured Notes") as of September 30, 2020:


(in millions, except for interest rates)	Principal		Interest rate
January 2025 Notes	$	600.0	9.500	%
January 2028 Notes	400.0		10.125	%
Total Senior Unsecured Notes	$	1,000.0

The net proceeds from the January 2025 Notes and January 2028 Notes were used to fund the tender offers and redemptions of the remaining principle amounts of the January 2022 Notes and March 2023 Notes. See Notes 6.a and 6.b to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of our Senior Unsecured Notes.

Supplemental Guarantor information

As discussed in Note 6.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report, on January 24, 2020, we issued $600.0 million in aggregate principal amount of the January 2025 Notes and $400.0 million in aggregate principal amount of the January 2028 Notes. As of September 30, 2020, $1.0 billion of our Senior Unsecured Notes remained outstanding. Each of our wholly owned subsidiaries, LMS and GCM (each, a "Guarantor," and together, the "Guarantors"), jointly and severally, and fully and unconditionally, guarantees the January 2025 Notes and the January 2028 Notes. We do not have any non-guarantor subsidiaries.

The guarantees are senior unsecured obligations of each Guarantor and rank equally in right of payment with other existing and future senior indebtedness of such Guarantor, and senior in right of payment to all existing and future subordinated indebtedness of such Guarantor. The guarantees of the Senior Unsecured Notes by the Guarantors are subject to certain Releases. The obligations of each Guarantor under its note guarantee are limited as necessary to prevent such note guarantee from constituting a fraudulent conveyance under applicable law. Further, the rights of holders of the Senior Unsecured Notes against the Guarantors may be limited under the U.S. Bankruptcy Code or state fraudulent transfer or conveyance law. Laredo is not restricted from making investments in the Guarantors and the Guarantors are not restricted from making intercompany distributions to Laredo or each other.

As we do not have any non-guarantor subsidiaries, the assets, liabilities and results of operations of the combined issuer and Guarantors are not materially different than the corresponding amounts presented in our unaudited consolidated financial statements included elsewhere in this Quarterly Report. Accordingly, we have omitted the summarized financial information of the issuer and the Guarantors that would otherwise be required.

Obligations and commitments

Our significant contractual obligations and commitments include our Senior Unsecured Notes, firm sale and transportation commitments, Senior Secured Credit Facility, asset retirement obligations and lease commitments. Since December 31, 2019, there have been no material changes other than to our debt and firm sale and transportation commitments. See Notes 6 and 19.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our debt.

We have committed to deliver, for sale or transportation, fixed volumes of product under certain contractual arrangements that specify the delivery of a fixed and determinable quantity. If not fulfilled, we are subject to firm transportation payments on excess pipeline capacity and other contractual penalties. Future firm sale and transportation commitments of

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$290.6 million are determined not probable to be incurred as of September 30, 2020 and are not recorded on the unaudited consolidated balance sheet. These commitments have decreased during the nine months ended September 30, 2020, and are mainly due to our fulfillment of contractual commitments, partially offset by changes to existing sales commitments. Of this amount, $90.8 million is related to transportation commitments with a certain pipeline pertaining to the gathering of our production from our established acreage that extends into 2024. We believe we will be able to meet the majority of this commitment, however, as development plans evolve and refine, we may be unable to meet a portion of this commitment. At this time, we are unable to satisfy this particular commitment with purchased oil. As such, we expensed firm transportation payments on excess capacity of $2.2 million during the three and nine months ended September 30, 2020. See Note 12.c to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our firm sale and transportation commitments.

Non-GAAP financial measures

The non-GAAP financial measures of Free Cash Flow and Adjusted EBITDA, as defined by us, may not be comparable to similarly titled measures used by other companies. Therefore, these non-GAAP financial measures should be considered in conjunction with net income or loss and other performance measures prepared in accordance with GAAP, such as operating income or loss or cash flows from operating activities. Free Cash Flow and Adjusted EBITDA should not be considered in isolation or as a substitute for GAAP measures, such as net income or loss, operating income or loss or any other GAAP measure of liquidity or financial performance.

Free Cash Flow

Free Cash Flow, a non-GAAP financial measure, does not represent funds available for future discretionary use because it excludes funds required for future debt service, capital expenditures, acquisitions, working capital, income taxes, franchise taxes and other commitments and obligations. However, our management believes Free Cash Flow is useful to management and investors in evaluating operating trends in our business that are affected by production, commodity prices, operating costs and other related factors. There are significant limitations to the use of Free Cash Flow as a measure of performance, including the lack of comparability due to the different methods of calculating Free Cash Flow reported by different companies.

The following table presents a reconciliation of net cash provided by operating activities (GAAP) to cash flows from operating activities before changes in operating assets and liabilities, net, less costs incurred, excluding non-budgeted acquisition costs, for the calculation of Free Cash Flow (non-GAAP) for the periods presented:


	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2020		2019		2020		2019
Net cash provided by operating activities	$	102,058	$	105,599	$	273,620	$	366,868
Less:
Change in current assets and liabilities, net	(8,360)		(21,183)		19,098		(48,305)
Change in noncurrent assets and liabilities, net	(3,425)		(1,124)		(11,252)		1,853
Cash flows from operating activities before changes in operating assets and liabilities, net	113,843		127,906		265,774		413,320
Less costs incurred, excluding non-budgeted acquisition costs:
Oil and natural gas properties(1)	41,128		76,837		269,937		365,839
Midstream service assets(1)	1,103		1,147		2,697		7,584
Other fixed assets	495		999		3,092		1,966
Total costs incurred, excluding non-budgeted acquisition costs	42,726		78,983		275,726		375,389
Free Cash Flow (non-GAAP)	$	71,117	$	48,923	$	(9,952)	$	37,931

_____________________________________________________________________________

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

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Adjusted EBITDA

Adjusted EBITDA is a non-GAAP financial measure that we define as net income or loss plus adjustments for share-settled equity-based compensation, depletion, depreciation and amortization, impairment expense, mark-to-market on derivatives, premiums paid for commodity derivatives that matured during the period, accretion expense, gains or losses on disposal of assets, interest expense, income taxes and other non-recurring income and expenses. Adjusted EBITDA provides no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, working capital movement or tax position. Adjusted EBITDA does not represent funds available for future discretionary use because it excludes funds required for debt service, capital expenditures, working capital, income taxes, franchise taxes and other commitments and obligations. However, our management believes Adjusted EBITDA is useful to an investor in evaluating our operating performance because this measure:

•is widely used by investors in the oil and natural gas industry to measure a company's operating performance without regard to items that can vary substantially from company to company depending upon accounting methods, the book value of assets, capital structure and the method by which assets were acquired, among other factors;

•helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure; and

• is used by our management for various purposes, including as a measure of operating performance, in presentations to our board of directors and as a basis for strategic planning and forecasting.

There are significant limitations to the use of Adjusted EBITDA as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss and the lack of comparability of results of operations to different companies due to the different methods of calculating Adjusted EBITDA reported by different companies. Our measurements of Adjusted EBITDA for financial reporting as compared to compliance under our debt agreements differ.

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The following table presents a reconciliation of net loss (GAAP) to Adjusted EBITDA (non-GAAP) for the periods presented:


	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2020		2019		2020		2019
Net loss	$	(237,432)	$	(264,629)	$	(708,241)	$	(100,738)
Plus:
Share-settled equity-based compensation, net	2,041		(1,739)		6,111		5,244
Depletion, depreciation and amortization	47,015		69,099		174,891		197,900

Impairment expense	196,088		397,890		789,235		397,890
Organizational restructuring expenses	—		5,965		4,200		16,371
Mark-to-market on derivatives:
(Gain) loss on derivatives, net	45,250		(96,684)		(162,049)		(136,713)
Settlements received for matured derivatives, net	51,840		25,245		186,435		48,827
Settlements received (paid) for early-terminated commodity derivatives, net	6,340		—		6,340		(5,409)
Premiums paid for commodity derivatives that matured during the period(1)	—		(1,415)		(477)		(7,664)
Accretion expense	1,102		1,005		3,325		3,077
(Gain) loss on disposal of assets, net	607		(1,294)		1,057		315
Interest expense	26,828		15,191		78,870		46,503
Loss on extinguishment of debt	—		—		13,320		—
Litigation settlement	—		—		—		(42,500)
Write-off of debt issuance costs	—		—		1,103		—
Income tax benefit	(2,398)		(2,467)		(7,154)		(812)



Adjusted EBITDA	$	137,281	$	146,167	$	386,966	$	422,291

_____________________________________________________________________________

(1)Reflects premiums incurred previously or upon settlement that are attributable to derivatives settled in the respective periods presented and were not a result of a hedge restructuring.

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.

There have been no material changes in our critical accounting policies and procedures during the nine months ended September 30, 2020. See our critical accounting policies in "Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" of the 2019 Annual Report.

New accounting standards

For discussion of new accounting standards, see Note 2 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.

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Off-balance sheet arrangements

Currently, we do not have any off-balance sheet arrangements other than our firm sale and transportation commitments, which are described in "—Obligations and commitments" and certain operating leases with a term less than or equal to 12 months. We have made an accounting policy election to not record the short-term operating leases on the unaudited consolidated balance sheets. See Notes 5 and 12.c to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information on our leases and commitments and contingencies, respectively.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term "market risk," in our case, refers to the risk of loss arising from adverse changes in oil, NGL and natural gas prices and in interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of how we view and manage our ongoing market risk exposures. All of our market risk-sensitive derivative instruments were entered into for hedging purposes, rather than for speculative trading.

Oil, NGL and natural gas price exposure

The fair values of our open commodity and contingent consideration derivative positions are largely determined by the relevant forward commodity price curves of the indexes associated with our open positions. We had a $88.5 million net asset position from the net fair values of our open commodity derivatives and a $0.5 million liability position from the potential contingent consideration payments associated with asset acquisitions, each as of September 30, 2020. The following table provides a sensitivity analysis of the projected incremental effect on loss before income taxes of a hypothetical 10% change in the relevant forward commodity price curves of the indexes associated with our open commodity and contingent consideration derivative positions as of September 30, 2020:


(in thousands)	10% Increase		10% Decrease
Commodity	$	(75,208)	$	77,264
Contingent consideration	(100)		105
Total	$	(75,308)	$	77,369

See Notes 9 and 10.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of our commodity and contingent consideration derivatives.

Interest rate risk

Our Senior Secured Credit Facility bears interest at a floating rate and our Notes bear interest at fixed rates. The maturity years, outstanding balances and interest rates on our long-term debt as of September 30, 2020 were as follows:


	Maturity year
(in millions except for interest rates)	2023			2025			Thereafter






January 2025 Notes	$	—		$	600.0		$	—
Fixed interest rate	—		%	9.500		%	—		%
January 2028 Notes	$	—		$	—		$	400.0
Fixed interest rate	—		%	—		%	10.125		%
Senior Secured Credit Facility	$	235.0		$	—		$	—
Floating interest rate	2.188		%	—		%	—		%

Due to the inherent volatility in interest rates, we have entered into an interest rate derivative swap to hedge interest rate risk associated with a portion of our anticipated outstanding debt under the Senior Secured Credit Facility. We will pay a fixed rate over the contract term for that portion. By removing a portion of the interest rate volatility associated with anticipated outstanding debt, we expect to mitigate, but not eliminate, the potential effects of variability in cash flows from operations.

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The fair value of our open interest rate derivative position is largely determined by the LIBOR interest rate forward curve associated with our open position. We had a $0.3 million total liability position from the net fair value of our open interest rate derivative as of September 30, 2020. The following table provides a sensitivity analysis of the projected incremental effect on loss before income taxes of a hypothetical 1% incremental addition to or subtraction from the relevant LIBOR forward curve interest rates associated with our open interest rate derivative position as of September 30, 2020:


(in thousands)	1% incremental addition to		1% incremental subtraction from
Interest rate	$	1,534	$	(1,534)

See Notes 6, 10.c and 19.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of our debt. See Notes 9 and 10.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of our interest rate derivative.

Counterparty and customer credit risk

We use commodity and interest rate derivatives to hedge our exposure to commodity prices and interest rate volatility, respectively. These transactions expose us to potential credit risk from our counterparties. We have entered into International Swaps and Derivatives Association Master Agreements ("ISDA Agreements") with each of our commodity and interest rate derivative counterparties, each of whom is also a lender in our Senior Secured Credit Facility, which, together with hedge agreements with lenders under such facility, is secured by our oil, NGL and natural gas reserves; therefore, we are not required to post any additional collateral. We do not require collateral from our commodity and interest rate derivative counterparties. The terms of the ISDA Agreements provide the non-defaulting or non-affected party the right to terminate the agreement upon the occurrence of certain events of default and termination events by a party and also provide for the marking to market of outstanding positions and the offset of the mark to market amounts owed to and by the parties (and in certain cases, the affiliates of the non-defaulting or non-affected party) upon termination; therefore, the credit risk associated with our commodity and interest rate derivative counterparties is somewhat mitigated. We minimize the credit risk in commodity and interest rate derivatives by: (i) limiting our exposure to any single counterparty, (ii) entering into commodity and interest rate derivatives only with counterparties that meet our minimum credit quality standard or have a guarantee from an affiliate that meets our minimum credit quality standard and (iii) monitoring the creditworthiness of our counterparties on an ongoing basis. We had a $90.2 million and $75.3 million total asset position from the net fair values of our open commodity contracts as of September 30, 2020 and December 31, 2019, respectively. See Notes 9 and 10.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for discussion of our commodity and interest rate derivatives.

We typically sell production to a relatively limited number of customers, as is customary in the exploration, development and production business. Our sales of purchased oil are currently made to three customers. Our joint operations accounts receivable are from a number of oil and natural gas companies, partnerships, individuals and others who own interests in the oil and natural gas properties operated by us.

The majority of our accounts receivable are unsecured. On occasion we require our customers to post collateral. We routinely assess the recoverability of all material trade and other receivables to determine collectability. As the operator of the majority of our wells, we have the ability to realize some or all of our joint operations account receivables through the netting of revenues. Management believes that any credit risk imposed by a concentration in the oil and natural gas industry is offset by the creditworthiness of our customer base and industry partners.

In the current market environment, we believe that the inability or failure of any one of our major purchasers to meet its obligations to us or its insolvency or liquidation would have an adverse effect on our financial condition and potentially our results of operations.

See Notes 2.e and 14 in the 2019 Annual Report for discussion of our accounts receivable and credit risk, respectively. See Note 15 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for discussion of revenue recognition.

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Customer performance risk

As a result of multiple factors affecting levels of supply and demand in global oil and gas markets, storage constraints created by excess oil supply in both domestic and international markets and the COVID-19 pandemic have created a risk that our customers will not be able to physically take possession of our oil. In the current market environment, we believe that the inability or failure of any one of our major customers to physically take possession of our oil would have an adverse effect on our financial condition and potentially our results of operations.

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Item 4. Controls and Procedures

Evaluation of disclosure controls and procedures

As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of Laredo's disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act), was performed under the supervision and with the participation of Laredo's management, including our principal executive and principal financial officers. Based on that evaluation, these officers concluded that Laredo's disclosure controls and procedures were not effective as of September 30, 2020 due to the material weakness in our internal control over financial reporting described below.

Notwithstanding the identified material weakness, Laredo's management, including our principal executive and principal financial officers have determined, based on the procedures we have performed, that the unaudited consolidated financial statements included in this Quarterly Report on Form 10-Q fairly present in all material respects our financial condition and results of operations for the three and nine months ended September 30, 2020 and 2019 in accordance with GAAP.

Material Weakness in Internal Control over Financial Reporting

A material weakness (as defined in Rule 12b-2 under the Exchange Act) is a deficiency, or a combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.

As noted in the second-quarter 2020 Quarterly Report, we identified deficiencies that represented a material weakness in our internal control over financial reporting as of March 31, 2020 with respect to the design and maintenance of controls over the determination of the estimated present value ("PV-10") of our reserves. Specifically, we did not design and maintain effective controls to sufficiently review the completeness and accuracy of the future production costs component of the estimated PV-10 of our reserves and, thus, failed to identify the omission of the transportation costs from the future costs required to develop certain of our reserves. These deficiencies had the effect of causing an overstatement of approximately $160 million in the estimated PV-10 of our reserves as of March 31, 2020, which caused an understatement in our full cost ceiling impairment expense and related adjustments for the quarter. An amendment was filed to our quarterly report on Form 10-Q for the quarter ended March 31, 2020 to correct the error and restate the financial statements for the first quarter of 2020 included in such report.

Remediation Plan

As part of our commitment to strengthening our internal control over financial reporting, we are implementing remedial actions under the oversight of the Audit Committee of our board of directors to address these deficiencies, including:

•implementation of additional (or enhanced) procedures to verify the completeness and accuracy of data inputs into the reserves application for pricing and operating expenses;

•implementation of additional (or enhanced) procedures to perform enhanced detailed reviews of reserves report components, including (but not necessarily limited to) pricing and operating expenses; and

•revision and communication of the accounting controls, policies and procedures relating to identifying and assessing changes that could potentially impact the system of internal control governing the full cost ceiling test calculation.

We will continue to monitor the design and effectiveness of these and other processes, procedures, policies and controls and make any further changes management determines appropriate. We believe the control improvements described above will remediate the material weakness that management has identified. However, this material weakness will not be considered remediated until the applicable remedial controls operate effectively for a sufficient period of time.

Limitations on the Effectiveness of Controls

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is designed to provide reasonable assurance as to the reliability of our financial reporting and the preparation of financial statements in accordance with GAAP. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

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Changes in Internal Control Over Financial Reporting

Except for changes we are making in connection with the implementation of the remediation plan described above, there were no changes in our internal control over financial reporting during the three months ended September 30, 2020 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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Part II

Item 1. Legal Proceedings

From time to time, we are subject to various legal proceedings arising in the ordinary course of business, including proceedings for which we may not have insurance coverage. While many of these matters involve inherent uncertainty 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.

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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 2019 Annual Report, Amendment No. 1 to our first-quarter 2020 Quarterly Report and our second-quarter 2020 Quarterly Report. Depending on the duration of the COVID-19 pandemic and its severity and related economic repercussions, the negative impact of many of the related risks discussed in our first-quarter and second-quarter 2020 Quarterly Reports may be heightened or exacerbated. Further, the risks described in such 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.

Risks related to our business

As a result of the volatility in prices for oil, NGL and natural gas, we have taken and may be required to take further write-downs of the carrying value of our properties.

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on prevailing commodity prices and specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we have been required to, and may be required to further, write down the carrying value of our properties. A write-down constitutes a non-cash charge to earnings.

Our unamortized cost of evaluated oil and natural gas properties being depleted exceeded the full cost ceiling as of March 31, 2020, June 30, 2020 and September 30, 2020 and, as such, we recorded non-cash full cost ceiling impairments of $177.2 million, $406.4 million and $196.1 million in the respective 2020 quarters. We recorded a non-cash full cost ceiling impairment of $620.6 million for the year ended December 31, 2019 and no such impairments were recorded during the years ended December 31, 2018 or 2017. If prices remain at or below the current levels, subject to numerous factors and inherent limitations, and all other factors remain constant, we will incur an additional non-cash full cost ceiling impairment in the fourth quarter of 2020 and 2021, which will have an adverse effect on our statement of operations. See "Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Pricing and reserves—Low commodity price potential impact on our fourth-quarter 2020 full cost ceiling impairment test" and Note 4 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for discussion of our full cost method of accounting.

Our operations may be exposed to significant delays, costs and liabilities as a result of environmental, health and safety requirements as well as new regulations applicable to our business activities.

We may incur significant delays, costs and liabilities as a result of federal, state and local environmental, health and safety requirements applicable to our exploration, development, marketing, transportation and production activities. At this time, it remains unclear how the possibility of a new presidential administration, a change of control in one or both houses of Congress, or a change in certain state-wide offices could affect the energy industry. New or changes to existing regulations could be significant and could affect a variety of exploration and development activities, including hydraulic fracturing and air emissions, among others. The costs and tax impacts of complying with such regulations could have a material adverse effect on our business, financial condition or results of operations.

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Item 2. Purchases of Equity Securities

The following table summarizes purchases of common stock by Laredo:



Period	Total number of shares purchased(1)	Weighted-average price paid per share		Total number of shares purchased as part of publicly announced plans	Maximum value that may yet be purchased under the program as of the respective period-end date
July 1, 2020 - July 31, 2020	53	$	17.16	—	$	—
August 1, 2020 - August 31, 2020	—	$	—	—	$	—
September 1, 2020 - September 30, 2020	780	$	15.94	—	$	—
Total	833			—

______________________________________________________________________________

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

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Item 3. Defaults Upon Senior Securities

None.

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Item 4. Mine Safety Disclosures

Not applicable.

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Item 5. Other Information

Disclosure required pursuant to Section 13(r) of the Exchange Act

Pursuant to Section 13(r) of the Exchange Act, we are required to disclose in our periodic 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 U.S. 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 have a member on our board of directors, and (ii) beneficially own more than 10% of the outstanding common stock of and are members of the board of directors of Endurance International Group Holdings, Inc. (together with its subsidiaries, "EIGI"). EIGI may therefore be deemed to be under common "control" with Laredo; however, this statement is not meant to be an admission that common control exists.

The disclosure below relates solely to activities conducted by EIGI. The disclosure does not relate to any activities conducted by Laredo 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.

Laredo understands that EIGI intends to disclose the following in its next annual or quarterly SEC report.

On October 16, 2020, EIGI’s subsidiaries MyDomain, LLC ("MyDomain") and HostGator.com LLC ("HostGator") suspended the domain KATRANGI.COM ("Domain Name") and an associated web hosting accounts (the "accounts"), which they determined were potentially linked to Electronics Katrangi Trading ("Katrangi"), an entity designated by the Office of Foreign Assets Control ("OFAC") as a Specially Designated National ("SDN") pursuant to 31 C.F.R. Part 544. During the quarter ended September 30, 2020, HostGator collected a total of USD $89.85 related to the account and MyDomain did not collect any fees. Neither the Domain Name nor the subscriber details for the MyDomain and HostGator accounts match the information on the SDN list. However, MyDomain and HostGator promptly suspended the Domain Name and the associated website and accounts upon discovering them on their platform. MyDomain and HostGator reported the Domain Name and the associated website to OFAC as property potentially associated with Katrangi and potentially subject to blocking pursuant to 31 C.F.R. Part 544.

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Item 6. Exhibits

Incorporated by reference (File No. 001-35380, unless otherwise indicated)

Exhibit

Description

Form

Exhibit

Filing Date

3.1

Amended and Restated Certificate of Incorporation of Laredo Petroleum Holdings, Inc.

8-K

3.1

12/22/2011

3.2

Certificate of Amendment to the Amended and Restated Certificate of Incorporation of Laredo Petroleum Holdings, Inc.

8-K

3.1

6/1/2020

3.3

Certificate of Ownership and Merger, dated as of December 30, 2013.

8-K

3.1

1/6/2014

3.4

Second Amended and Restated Bylaws of Laredo Petroleum, Inc.

10-K

3.3

2/17/2016

4.1

Form of Common Stock Certificate.

8-A12B/A

4.1

1/7/2014

10.1

Fifth Amendment to the Fifth Amended and Restated Credit Agreement, dated as of October 22, 2020, 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.

8-K

10.1

10/22/2020

22.1

List of Issuers and Guarantor Subsidiaries

10-Q

22.1

5/7/2020

31.1*

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

31.2*

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

32.1**

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

101

The following financial information from Laredo’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2020, 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.

104

Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

______________________________________________________________________________

* Filed herewith.

** Furnished herewith.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


	LAREDO PETROLEUM, INC.

Date: November 5, 2020	By:	/s/ Jason Pigott
		Jason Pigott
		President and Chief Executive Officer
		(principal executive officer)

Date: November 5, 2020	By:	/s/ Bryan J. Lemmerman
		Bryan J. Lemmerman
		Senior Vice President and Chief Financial Officer
		(principal financial officer)

Date: November 5, 2020	By:	/s/ Jessica R. Wren
		Jessica R. Wren
		Interim Principal Accounting Officer
		(principal accounting officer)