Vital Energy, Inc. - Quarter Report: 2020 March (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 March 31, 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 May 4, 2020: 239,398,217

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 March 31, 2020 and December 31, 2019	1
Consolidated statements of operations for the three months ended March 31, 2020 and 2019	2
Consolidated statements of stockholders' equity continuous quarterly presentation ended March 31, 2020 and 2019	3
Consolidated statements of cash flows for the three months ended March 31, 2020 and 2019	4
Condensed notes to the consolidated financial statements:	5
Note 1—Organization and basis of presentation	5
Note 2—New accounting standards	5
Note 3—Acquisitions and divestiture	6
Note 4—Property and equipment	7
Note 5—Leases	9
Note 6—Debt	9
Note 7—Stockholders' equity	11
Note 8—Equity Incentive Plan	12
Note 9—Derivatives	17
Note 10—Fair value measurements	20
Note 11—Net income (loss) per common share	22
Note 12—Commitments and contingencies	23
Note 13—Supplemental cash flow and non-cash information	24
Note 14—Asset retirement obligations	25
Note 15—Revenue recognition	25
Note 16—Income taxes	25
Note 17—Related parties	26
Note 18—Subsequent events	26
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations	29
Item 3. Quantitative and Qualitative Disclosures About Market Risk	46
Item 4. Controls and Procedures	48
Part II	49
Item 1. Legal Proceedings	49
Item 1A. Risk Factors	49
Item 2. Purchases of Equity Securities	52
Item 3. Defaults Upon Senior Securities	53
Item 4. Mine Safety Disclosures	54
Item 5. Other Information	55
Item 6. Exhibits	56
SIGNATURES	57

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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 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 the Organization of the Petroleum Exporting Countries members and other oil exporting nations ("OPEC+");


•	the threat, occurrence, potential duration or other implications of epidemic or pandemic diseases, including the recent outbreak of a novel strain of coronavirus ("COVID-19"), or any government response to such occurrence or threat;


•	changes in domestic and global production, supply and demand for oil, NGL and natural gas, including the recent decrease in demand and oversupply of oil and natural gas as a result of the COVID-19 pandemic and actions by OPEC+;


•	the pipeline and storage constraints in the Permian Basin and the possibility of future production curtailment in the State of Texas;


•	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 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 or international legal, tax, political, administrative or economic conditions, including trade policies or regulations that restrict imports or exports from the United States or 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;


•	the ongoing instability and uncertainty in the United States 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;


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

iii

Table of Contents


•	the availability and costs of sufficient pipeline and transportation facilities and gathering and processing capacity;


•	our ability 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 potentially insufficient refining capacity in the United States Gulf Coast to refine all of the light sweet crude oil being produced in the United States, which could result in widening price discounts to world 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;


•	drilling and operating risks, including risks 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, 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.

Table of Contents

Part I

Item 1. Consolidated Financial Statements (Unaudited)

Laredo Petroleum, Inc.

Consolidated balance sheets

(in thousands, except share data)

(Unaudited)



	March 31, 2020			December 31, 2019
Assets
Current assets:
Cash and cash equivalents	$	62,777		$	40,857
Accounts receivable, net	75,588			85,223
Derivatives	270,686			51,929
Other current assets	18,245			22,470
Total current assets	427,296			200,479
Property and equipment:
Oil and natural gas properties, full cost method:
Evaluated properties	7,610,086			7,421,799
Unevaluated properties not being depleted	130,077			142,354
Less accumulated depletion and impairment	(5,799,703		)	(5,725,114		)
Oil and natural gas properties, net	1,940,460			1,839,039
Midstream service assets, net	118,539			128,678
Other fixed assets, net	32,148			32,504
Property and equipment, net	2,091,147			2,000,221
Derivatives	48,397			23,387
Operating lease right-of-use assets	24,381			28,343
Other noncurrent assets, net	12,871			12,007
Total assets	$	2,604,092		$	2,264,437
Liabilities and stockholders' equity
Current liabilities:
Accounts payable and accrued liabilities	$	65,580		$	40,521
Accrued capital expenditures	52,600			36,328
Undistributed revenue and royalties	28,186			33,123
Derivatives	875			7,698
Operating lease liabilities	12,891			14,042
Other current liabilities	25,552			39,184
Total current liabilities	185,684			170,896
Long-term debt, net	1,257,382			1,170,417
Asset retirement obligations	61,679			60,691
Operating lease liabilities	13,913			17,208
Other noncurrent liabilities	5,764			3,351
Total liabilities	1,524,422			1,422,563
Commitments and contingencies
Stockholders' equity:
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued as of March 31, 2020 and December 31, 2019	—			—
Common stock, $0.01 par value, 450,000,000 shares authorized and 239,400,163 and 237,292,086 issued and outstanding as of March 31, 2020 and December 31, 2019, respectively	2,394			2,373
Additional paid-in capital	2,388,035			2,385,355
Accumulated deficit	(1,310,759		)	(1,545,854		)
Total stockholders' equity	1,079,670			841,874
Total liabilities and stockholders' equity	$	2,604,092		$	2,264,437

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 March 31,
	2020			2019
Revenues:
Oil sales	$	119,978		$	129,171
NGL sales	11,558			32,235
Natural gas sales	4,349			11,970
Midstream service revenues	2,683			2,883
Sales of purchased oil	66,424			32,688
Total revenues	204,992			208,947
Costs and expenses:
Lease operating expenses	22,040			22,609
Production and ad valorem taxes	9,244			7,219
Transportation and marketing expenses	13,544			4,759
Midstream service expenses	1,170			1,603
Costs of purchased oil	79,297			32,691
General and administrative	12,562			21,519
Depletion, depreciation and amortization	61,302			63,098
Impairment expense	26,250			—
Other operating expenses	1,106			1,052
Total costs and expenses	226,515			154,550
Operating income (loss)	(21,523		)	54,397
Non-operating income (expense):
Gain (loss) on derivatives, net	297,836			(48,365		)
Interest expense	(24,970		)	(15,547		)
Loss on extinguishment of debt	(13,320		)	—
Loss on disposal of assets, net	(602		)	(939		)
Other income, net	91			867
Total non-operating income (expense), net	259,035			(63,984		)
Income (loss) before income taxes	237,512			(9,587		)
Income tax (expense) benefit:
Deferred	(2,417		)	96
Total income tax (expense) benefit	(2,417		)	96
Net income (loss)	$	235,095		$	(9,491	)
Net income (loss) per common share:
Basic	$	1.01		$	(0.04	)
Diluted	$	1.01		$	(0.04	)
Weighted-average common shares outstanding:
Basic	232,351			230,476
Diluted	233,458			230,476

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			Additional paid-in capital			Shares		Amount			Accumulated deficit			Total
Balance, December 31, 2019	237,292		$	2,373		$	2,385,355		—		$	—		$	(1,545,854	)	$	841,874
Restricted stock awards	2,771		28			(28		)	—		—			—			—
Restricted stock forfeitures	(139	)	(2		)	2			—		—			—			—
Stock exchanged for tax withholding	—		—			—			524		(640		)	—			(640		)
Retirement of treasury stock	(524	)	(5		)	(635		)	(524	)	640			—			—
Share-settled equity-based compensation	—		—			3,341			—		—			—			3,341
Net income	—		—			—			—		—			235,095			235,095
Balance, March 31, 2020	239,400		$	2,394		$	2,388,035		—		$	—		$	(1,310,759	)	$	1,079,670



	Common stock					Additional paid-in capital			Treasury stock (at cost)					Accumulated deficit
	Shares		Amount			Additional paid-in capital			Shares		Amount			Accumulated deficit			Total
Balance, December 31, 2018	233,936		$	2,339		$	2,375,286		—		$	—		$	(1,203,395	)	$	1,174,230
Restricted stock awards	5,986		60			(60		)	—		—			—			—
Restricted stock forfeitures	(48	)	—			—			—		—			—			—
Stock exchanged for tax withholding	—		—			—			683		(2,612		)	—			(2,612		)
Stock exchanged for cost of exercise of stock options	—		—			—			18		(76		)	—			(76		)
Retirement of treasury stock	(701	)	(7		)	(2,681		)	(701	)	2,688			—			—
Exercise of stock options	18		—			76			—		—			—			76
Share-settled equity-based compensation	—		—			9,305			—		—			—			9,305
Net loss	—		—			—			—		—			(9,491		)	(9,491		)
Balance, March 31, 2019	239,191		$	2,392		$	2,381,926		—		$	—		$	(1,212,886	)	$	1,171,432

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)



	Three months ended March 31,
	2020			2019
Cash flows from operating activities:
Net income (loss)	$	235,095		$	(9,491	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Share-settled equity-based compensation, net	2,376			7,406
Depletion, depreciation and amortization	61,302			63,098
Impairment expense	26,250			—
Mark-to-market on derivatives:
(Gain) loss on derivatives, net	(297,836		)	48,365
Settlements received for matured commodity derivatives, net	47,723			102
Premiums paid for commodity derivatives	(477		)	(4,016		)
Amortization of debt issuance costs	1,217			846
Amortization of operating lease right-of-use assets	4,377			3,056
Loss on extinguishment of debt	13,320			—
Deferred income tax expense (benefit)	2,417			(96		)
Other, net	1,327			3,874
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable, net	9,635			(13,373		)
Decrease (increase) in other current assets	4,033			(2,769		)
(Increase) decrease in other noncurrent assets, net	(2,964		)	57
Increase in accounts payable and accrued liabilities	25,059			7,140
(Decrease) increase in undistributed revenue and royalties	(4,937		)	2,889
Decrease in other current liabilities	(15,082		)	(30,637		)
(Decrease) increase in other noncurrent liabilities	(3,246		)	1,007
Net cash provided by operating activities	109,589			77,458
Cash flows from investing activities:
Acquisitions of oil and natural gas properties, net	(22,876		)	—
Capital expenditures:
Oil and natural gas properties	(135,376		)	(152,729		)
Midstream service assets	(761		)	(2,262		)
Other fixed assets	(829		)	(505		)
Proceeds from dispositions of capital assets, net of selling costs	51			43
Net cash used in investing activities	(159,791		)	(155,453		)
Cash flows from financing activities:
Borrowings on Senior Secured Credit Facility	—			80,000
Payments on Senior Secured Credit Facility	(100,000		)	—
Issuance of January 2025 Notes and January 2028 Notes	1,000,000			—
Extinguishment of debt	(808,855		)	—
Stock exchanged for tax withholding	(640		)	(2,612		)
Payments for debt issuance costs	(18,383		)	—
Net cash provided by financing activities	72,122			77,388
Net increase (decrease) in cash and cash equivalents	21,920			(607		)
Cash and cash equivalents, beginning of period	40,857			45,151
Cash and cash equivalents, end of period	$	62,777		$	44,544

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 March 31, 2020, results of operations for the three months ended March 31, 2020 and 2019 and cash flows for the three months ended March 31, 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 Note 8 pertaining to the Company's 2020 performance unit awards and phantom unit awards.

Reclassifications

Certain amounts in the accompanying 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 ("FASB") to the Accounting Standards Codification ("ASC") and has determined there are no ASUs that are not yet adopted and meaningful to disclose as of March 31, 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



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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 months ended March 31, 2020.

Note 3—Acquisitions and divestiture of evaluated and unevaluated oil and natural gas properties

a. 2020 Asset acquisition and divestiture

On February 4, 2020, the Company closed a transaction for $22.5 million, subject to post-closing purchase price adjustments, acquiring 1,180 net acres and divesting 80 net acres in Howard County, Texas. All transaction costs were capitalized and were included in "Oil and natural gas properties" on the consolidated balance sheet.

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 purchase price adjustments 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 million if the arithmetic average of the monthly settlement West Texas Intermediate ("WTI") NYMEX prices for each consecutive calendar month for the one-year period beginning January 1, 2020 through December 31, 2020 exceeds $60.00 per barrel. The fair value of the contingent consideration was $6.2 million as of the acquisition date, which is recorded as part of the basis in the oil and natural gas properties acquired. See Note 10.a for the fair value of the contingent consideration as of March 31, 2020. All transaction costs were capitalized and were included in "Oil and natural gas properties" on the consolidated balance sheet. This acquisition was primarily financed through borrowings under the Senior Secured Credit Facility. Post-closing is expected to be finalized during the second quarter of 2020.

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

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 and subject to customary post-closing purchase price adjustments. This acquisition was financed through borrowings under the Senior Secured Credit Facility. Post-closing is expected to be finalized during the second quarter of 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 revenues of proved undeveloped and probable reserves are reduced by additional reserve adjustment factors. These assumptions represent Level 3 inputs under the fair value hierarchy, as described in Note 10 in the 2019 Annual Report.



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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.

Note 4—Property and equipment

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



(in thousands)	March 31, 2020			December 31, 2019
Evaluated oil and natural gas properties	$	7,610,086		$	7,421,799
Less accumulated depletion and impairment	(5,799,703		)	(5,725,114		)
Evaluated oil and natural gas properties, net	1,810,383			1,696,685

Unevaluated oil and natural gas properties not being depleted	130,077			142,354

Midstream service assets	180,992			180,932
Less accumulated depreciation and impairment	(62,453		)	(52,254		)
Midstream service assets, net	118,539			128,678

Depreciable other fixed assets	37,515			37,894
Less accumulated depreciation and amortization	(24,051		)	(23,649		)
Depreciable other fixed assets, net	13,464			14,245

Land	18,684			18,259

Total property and equipment, net	$	2,091,147		$	2,000,221

See Note 10.b for discussion of impairments of long-lived assets during the three months ended March 31, 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.



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Condensed notes to the consolidated financial statements

(Unaudited)

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.

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



	Three months ended March 31,
(in thousands)	2020		2019
Property acquisition costs:
Evaluated	$	7,586	$	—
Unevaluated	15,556		—
Exploration costs	6,710		7,505
Development costs	146,158		152,717
Total oil and natural gas properties costs incurred	$	176,010	$	160,222

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

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



	Three months ended March 31,
(in thousands)	2020		2019
Capitalized employee-related costs	$	4,505	$	6,682

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



	Three months ended March 31,
	2020		2019
Depletion expense of evaluated oil and natural gas properties	$	57,752	$	59,370
Depletion expense per BOE sold	$	7.33	$	8.76

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



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Condensed notes to the consolidated financial statements

(Unaudited)

Realized Prices are utilized to calculate the discounted 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.

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



	March 31, 2020		December 31, 2019		September 30, 2019		June 30, 2019		March 31, 2019
Benchmark Prices:
Oil ($/Bbl)	$	52.23	$	52.19	$	54.27	$	57.90	$	59.52
NGL ($/Bbl)⁽¹⁾	$	19.36	$	21.14	$	23.93	$	28.21	$	30.34
Natural gas ($/MMBtu)	$	0.58	$	0.87	$	0.85	$	1.14	$	1.58
Realized Prices:
Oil ($/Bbl)	$	52.47	$	52.12	$	52.86	$	55.69	$	56.72
NGL ($/Bbl)	$	10.47	$	12.21	$	14.78	$	18.64	$	20.46
Natural gas ($/Mcf)	$	0.28	$	0.53	$	0.52	$	0.70	$	1.09

_____________________________________________________________________________


(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 March 31,
(in thousands)	2020		2019
Full cost ceiling impairment expense	$	16,733	$	—

Note 5—Leases

The Company has recognized operating lease right-of-use assets and operating lease liabilities on the unaudited consolidated balance sheet 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 income (loss) during the period as well as those that are capitalized as part of the cost of another asset in accordance with other GAAP.

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 March 31, 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 will be made on July 15, 2020, and will consist 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



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Condensed notes to the consolidated financial statements

(Unaudited)

Secured Credit Facility, which limit the Company's ability to incur indebtedness, make restricted payments, grant liens and dispose of assets.

The January 2025 Notes and January 2028 Notes are fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain automatic customary releases, including the sale, disposition or transfer of all of the capital stock or of all or substantially all of the assets of a subsidiary guarantor to one or more persons that are not the Company or a restricted subsidiary, exercise of legal defeasance or covenant defeasance options or satisfaction and discharge of the applicable indenture, designation of a subsidiary guarantor as a non-guarantor restricted subsidiary or as an unrestricted subsidiary in accordance with the applicable indenture, release from guarantee under the Senior Secured Credit Facility, or liquidation or dissolution (collectively, the "Releases").

The Company received net proceeds of approximately $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 March 31, 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 $950.0 million each, with $275.0 million outstanding and was subject to an interest rate of 2.43%. 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 March 31, 2020 and December 31, 2019, the Company had one letter of credit outstanding of $14.7 million under the Senior Secured Credit Facility. The Senior Secured Credit Facility is fully and unconditionally guaranteed by LMS and GCM. For additional information see Note 7.d in the 2019 Annual Report. See Note 18.a for discussion of the semi-annual borrowing base



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Condensed notes to the consolidated financial statements

(Unaudited)

redetermination of the Senior Secured Credit Facility and an increase in the outstanding letter of credit subsequent to March 31, 2020.

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

d. Long-term debt, net

The following table summarizes the net presentation of the Company's long-term debt and debt issuance costs on the unaudited consolidated balance sheets as of the dates presented:



	March 31, 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		(10,532		)	589,468		—		—			—
January 2028 Notes⁽²⁾	400,000		(7,086		)	392,914		—		—			—
Senior Secured Credit Facility⁽³⁾	275,000		—			275,000		375,000		—			375,000
Total	$	1,275,000	$	(17,618	)	$	1,257,382	$	1,175,000	$	(4,583	)	$	1,170,417

______________________________________________________________________________


(1)	During the three months ended March 31, 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 statements of operations.


(2)	Debt issuance costs for the January 2025 Notes and 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 $4.1 million and $4.5 million as of March 31, 2020 and December 31, 2019, respectively, are reported in "Other noncurrent assets, net" on the unaudited consolidated balance sheets.

Note 7—Stockholders' equity

a. Potential Reverse Stock Split and Authorized Share Reduction

The Company is authorized by its amended and restated certificate of incorporation ("Certificate of Incorporation") to issue a total of 500,000,000 shares of capital stock, consisting of 450,000,000 shares of common stock, par value $0.01 per share ("Common Stock"), and 50,000,000 shares of preferred stock, par value $0.01 per share.

On March 17, 2020, the board of directors authorized an amendment to the Certificate of Incorporation to effect, at the discretion of the board of directors (i) a reverse stock split ("Reverse Stock Split") that will 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"). The amendments must be approved by stockholders for the board of directors to effect the Reverse Stock Split and the Authorized Share Reduction. If this proposal is approved by stockholders and the Reverse Stock Split is effected, between every 5 to 20 outstanding shares of Common Stock would be combined and reclassified into one share of Common Stock. Additionally, if this proposal is approved by stockholders and the Authorized Share Reduction is effected, the number of authorized shares of Common Stock would be proportionally reduced by the Reverse Stock Split ratio, resulting in a decrease from 450,000,000 authorized shares of Common Stock to between 22,500,000 and 90,000,000 authorized shares of Common Stock. The Company will pay cash in lieu of fractional shares resulting from the Reverse Stock Split.

Notwithstanding approval of this proposal by stockholders, the board of directors will have the sole authority to elect whether or not and when to amend the Certificate of Incorporation to effect the Reverse Stock Split and the Authorized Share Reduction. As such, the actual timing for implementation of the Reverse Stock Split and the Authorized Share Reduction



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Condensed notes to the consolidated financial statements

(Unaudited)

would be determined by the board of directors, in its sole discretion. The actual number of authorized shares of Common Stock after giving effect to the Reverse Stock Split, if and when effected, will depend on the Reverse Stock Split ratio that is ultimately determined by the board of directors.

The Company expects the annual meeting of stockholders to be held on May 14, 2020.

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.

Note 8—Equity Incentive Plan

The Laredo Petroleum, Inc. Omnibus Equity Incentive Plan, as amended and restated as of May 16, 2019 (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. The Equity Incentive Plan allows for the issuance of up to 29,850,000 shares.

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 three months ended March 31, 2020:



(in thousands, except for weighted-average grant-date fair value)	Restricted stock awards		Weighted-average grant-date fair value (per share)
Outstanding as of December 31, 2019	5,498		$	4.29
Granted	2,771		$	0.92
Forfeited	(139	)	$	5.06
Vested⁽¹⁾	(1,867	)	$	5.03
Outstanding as of March 31, 2020	6,263		$	2.56

_____________________________________________________________________________


(1)	The aggregate intrinsic value of vested restricted stock awards for the three months ended March 31, 2020 was $2.4 million.

The Company utilizes the closing stock price on the grant date to determine the fair value of restricted stock awards. As of March 31, 2020, unrecognized equity-based compensation related to the restricted stock awards expected to vest was $13.8 million. Such cost is expected to be recognized over a weighted-average period of 1.93 years.



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Condensed notes to the consolidated financial statements

(Unaudited)

b. Stock option awards

The following table reflects the stock option award activity for the three months ended March 31, 2020:



(in thousands, except for weighted-average exercise price and weighted-average remaining contractual term)	Stock option awards	Weighted-average exercise price (per option)		Weighted-average remaining contractual term (years)
Outstanding as of December 31, 2019	340	$	12.56	5.00
Exercised	—	$	—
Expired or canceled	—	$	—
Forfeited	—	$	—
Outstanding as of March 31, 2020	340	$	12.56	4.71
Vested and exercisable as of March 31, 2020⁽¹⁾	330	$	12.51	4.64
Expected to vest as of March 31, 2020⁽²⁾	10	$	14.12	6.89

_____________________________________________________________________________


(1)	The vested and exercisable stock option awards as of March 31, 2020 had no intrinsic value.


(2)	The expected to vest stock option awards as of March 31, 2020 had no intrinsic value.

As of March 31, 2020, unrecognized equity-based compensation related to stock option awards expected to vest was $0.1 million. Such cost is expected to be recognized over a weighted-average period of 0.92 years. See Note 8.b in the 2019 Annual Report for additional information on the Company's stock option awards.

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 three months ended March 31, 2020:



(in thousands, except for weighted-average grant-date fair value)	Performance share awards		Weighted-average grant-date fair value (per share)
Outstanding as of December 31, 2019	2,300		$	5.34
Forfeited	(32	)	$	6.66
Vested⁽¹⁾	(158	)	$	18.96
Outstanding as of March 31, 2020	2,110		$	4.30

______________________________________________________________________________

(1)

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 first quarter of 2020.



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Condensed notes to the consolidated financial statements

(Unaudited)

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 March 31, 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	$	2.45		$	3.98		$	10.08
Expense per performance share as of March 31, 2020	$	2.45		$	3.98		$	10.08
Performance Criteria:
(1/2) ROACE Factor:
Grant-date fair value per performance share	$	2.59		$	3.49		$	8.36
Estimated payout for expense as of March 31, 2020	175		%	175		%	75		%
Expense per performance share as of March 31, 2020⁽²⁾	$	4.53		$	6.11		$	6.27
Combined:
Grant-date fair value per performance share⁽³⁾	$	2.52		$	3.74		$	9.22
Expense per performance share as of March 31, 2020⁽⁴⁾	$	3.49		$	5.05		$	8.18

______________________________________________________________________________


(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)	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.


(3)	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.


(4)	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 March 31, 2020, unrecognized equity-based compensation related to the performance share awards expected to vest was $5.8 million. Such cost is expected to be recognized over a weighted-average period of 1.77 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. If earned, the payout ranges from 0 to 1,000,000 shares in the Company's common stock per the vesting schedule. This award is subject to a combination of market and service vesting criteria, therefore, a Monte Carlo simulation prepared by an independent third party was utilized to determine the grant-date fair value with the associated expense recognized over the requisite service period. The payout of this award is based on the highest 50 consecutive trading day average closing stock price of the Company that occurs during the performance period that commenced on June 3, 2019 and ends on June 3, 2022 ("Final Date"). Of the earned outperformance shares, one-third of the award will vest on the Final Date, one-third will vest on the first anniversary of the Final Date and one-third will vest on the second anniversary of the Final Date, provided that the participant has been continuously employed with the Company through the applicable vesting date.

As of March 31, 2020, unrecognized equity-based compensation related to the outperformance share award expected to vest was $0.5 million. Such cost is expected to be recognized over a weighted-average period of 4.25 years.

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:



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Condensed notes to the consolidated financial statements

(Unaudited)

(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%. 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 three months ended March 31, 2020:



(in thousands)		Performance units
Outstanding as of December 31, 2019⁽¹⁾		—
Granted⁽²⁾		2,458
Outstanding as of March 31, 2020		2,458

______________________________________________________________________________


(1)	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 second quarter of 2019. See Note 8.b in the 2019 Annual Report for additional information on the award conversion.

(2)

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 March 31, 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	2.75 years
Risk-free interest rate⁽¹⁾	0.27		%
Dividend yield	—		%
Expected volatility⁽²⁾	97.85		%
Closing stock price on March 31, 2020	$	0.38
Fair value per performance unit as of March 31, 2020	$	0.43
Expense per performance unit as of March 31, 2020	$	0.43
Performance criteria:
(1/3) ROACE Factor:
Fair value assumptions:
Closing stock price on March 31, 2020	$	0.38
Fair value per performance unit as of March 31, 2020	$	0.38
Estimated payout for expense as of March 31, 2020	100.00		%
Expense per performance unit as of March 31, 2020⁽³⁾	$	0.38
Combined:
Fair value per performance unit as of March 31, 2020⁽⁴⁾	$	0.41
Expense per performance unit as of March 31, 2020⁽⁵⁾	$	0.41

______________________________________________________________________________


(1)	The remaining performance period matched zero-coupon risk-free interest rate was derived from the United States ("U.S.") Treasury constant maturities yield curve on March 31, 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 March 31, 2020, unrecognized equity-based compensation related to the performance unit awards expected to vest was $1.0 million. Such cost is expected to be recognized over a weighted-average period of 3.00 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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date 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 three months ended March 31, 2020:



(in thousands, except for weighted-average grant-date fair value)	Phantom units	Fair value as of March 31, 2020 (per unit)
Outstanding as of December 31, 2019	—	$	—
Granted	1,509	$	0.38
Outstanding as of March 31, 2020	1,509	$	0.38

The Company utilizes the closing stock price on the last day of each reporting period to determine the fair value of phantom unit awards and the life-to-date recognized expense is adjusted accordingly. As of March 31, 2020, unrecognized equity-based compensation related to the phantom unit awards expected to vest was $0.5 million. Such cost is expected to be recognized over a weighted-average period of 3.00 years.

g. Equity-based compensation

The following table reflects equity-based compensation expense for the periods presented:



	Three months ended March 31,
(in thousands)	2020			2019
Equity awards:
Restricted stock awards	$	2,498		$	5,323
Performance share awards	756			3,164
Outperformance share award	44			—
Stock option awards	43			818
Total share-settled equity-based compensation, gross	3,341			9,305
Less amounts capitalized	(965		)	(1,899		)
Total share-settled equity-based compensation, net	2,376			7,406
Liability awards:
Phantom unit awards	25			—
Performance unit awards	24			238
Total cash-settled equity-based compensation, gross	49			238
Less amounts capitalized	(10		)	(46		)
Total cash-settled equity-based compensation, net	39			192
Total equity-based compensation, net	$	2,415		$	7,598

Note 9—Derivatives

The Company has two types of derivative instruments as of March 31, 2020: (i) sales volumes commodity derivatives ("Commodity") and (ii) contingent consideration derivative ("Contingent consideration"). For further discussion, see Note 10.a for fair value measurement on a recurring basis. See Note 18.b for discussion of the derivatives entered into subsequent to March 31, 2020.

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 Notes 2.f and 9 in the 2019 Annual Report for discussion of the Company's significant accounting policies for derivatives and information on the transaction types and settlement indexes, respectively. The Brent ICE to WTI NYMEX basis swaps, which the Company entered into in the first quarter of 2020, are settled based on the differential between the basis swaps' fixed



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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 three months ended March 31, 2020, the Company completed a hedge restructuring by early terminating collars and entering into new swaps.

The following table details the commodity derivatives that were terminated:



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

b. Contingent consideration

See Note 3.b for discussion of the circumstances surrounding the contingent consideration and Note 10.a for the associated fair value as of March 31, 2020. At each quarterly reporting period, the Company remeasures the contingent consideration with the changes in fair value recognized in earnings.



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c. Open commodity derivative positions

The following table summarizes open commodity derivative positions as of March 31, 2020, for commodity derivatives that were entered into through March 31, 2020, for the settlement periods presented:



	Remaining year 2020			Year 2021
Oil:
WTI NYMEX - Swaps:
Volume (Bbl)	5,390,000			—
Weighted-average price ($/Bbl)	$	59.50		$	—
Brent ICE:
Swaps:
Volume (Bbl)	1,787,500			1,825,000
Weighted-average price ($/Bbl)	$	63.07		$	60.13
Collars:
Volume (Bbl)	—			584,000
Weighted-average floor price ($/Bbl)	$	—		$	45.00
Weighted-average ceiling price ($/Bbl)	$	—		$	59.50
Total Brent ICE:
Total volume (Bbl)	1,787,500			2,409,000
Weighted-average floor price ($/Bbl)	$	63.07		$	56.46
Weighted-average ceiling price ($/Bbl)	$	63.07		$	59.98
Total oil volume (Bbl)	7,177,500			2,409,000
Brent ICE to WTI NYMEX - Basis Swaps
Volume (Bbl)	2,695,000			—
Weighted-average differential ($/Bbl)	$	5.09		$	—
NGL - Mont Belvieu OPIS:
Purity Ethane - Swaps:
Volume (Bbl)	275,000			912,500
Weighted-average price ($/Bbl)	$	13.60		$	12.01
Non-TET Propane - Swaps:
Volume (Bbl)	935,000			730,000
Weighted-average price ($/Bbl)	$	26.58		$	25.52
Non-TET Normal Butane - Swaps:
Volume (Bbl)	330,000			255,500
Weighted-average price ($/Bbl)	$	28.69		$	27.72
Non-TET Isobutane - Swaps:
Volume (Bbl)	82,500			67,525
Weighted-average price ($/Bbl)	$	29.99		$	28.79
Non-TET Natural Gasoline - Swaps:
Volume (Bbl)	302,500			237,250
Weighted-average price ($/Bbl)	$	45.15		$	44.31
Total NGL volume (Bbl)	1,925,000			2,202,775
Natural gas:
Henry Hub NYMEX - Swaps:
Volume (MMBtu)	17,875,000			27,922,500
Weighted-average price ($/MMBtu)	$	2.72		$	2.53
Waha Inside FERC to Henry Hub NYMEX - Basis Swaps:
Volume (MMBtu)	31,625,000			23,360,000
Weighted-average differential ($/MMBtu)	$	(0.82	)	$	(0.47	)



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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 Notes 9 and 18.b 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 summarize the Company's derivatives' three-level fair value hierarchy by (i) assets and liabilities, (ii) current and noncurrent, (iii) commodity derivatives and contingent consideration derivative and (iv) oil, NGL, natural gas and/or deferred premiums, on a gross basis and the net presentation included in "Derivatives" on the unaudited consolidated balance sheets as of the dates presented:



	March 31, 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	$	—	$	222,125		$	—	$	222,125		$	—		$	222,125
Commodity - NGL	—		32,721			—		32,721			—			32,721
Commodity - Natural gas	—		17,582			—		17,582			(1,742		)	15,840
Commodity - Oil deferred premiums	—		—			—		—			—			—
Noncurrent:
Commodity - Oil	$	—	$	29,220		$	—	$	29,220		$	—		$	29,220
Commodity - NGL	—		14,600			—		14,600			—			14,600
Commodity - Natural gas	—		4,382			—		4,382			195			4,577
Liabilities:
Current:
Commodity - Oil	$	—	$	—		$	—	$	—		$	—		$	—
Commodity - NGL	—		—			—		—			—			—
Commodity - Natural gas	—		(1,742		)	—		(1,742		)	1,742			—
Commodity - Oil deferred premiums	—		—			—		—			—			—
Contingent consideration - Oil	—		(875		)	—		(875		)	—			(875		)
Noncurrent:
Commodity - Natural gas	—		195			—		195			(195		)	—
Net derivative asset (liability) positions	$	—	$	318,208		$	—	$	318,208		$	—		$	318,208



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	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			—
Contingent consideration - Oil	$	—	$	(7,350	)	$	—		$	(7,350	)	$	—		$	(7,350	)
Noncurrent:
Commodity - Natural gas	—		—			—			—			—			—
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 March 31, 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.

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



	Three months ended March 31,
(in thousands)	2020			2019
Balance of Level 3 at beginning of period	$	(477	)	$	(16,565	)
Change in net present value of commodity derivative deferred premiums⁽¹⁾	—			(95		)
Settlements of commodity derivative deferred premiums	477			4,016
Balance of Level 3 at end of period	$	—		$	(12,644	)

____________________________________________________________________________


(1)	This amount is included in "Interest expense" on the unaudited consolidated statements of operations for the three months ended March 31, 2019.

Contingent consideration

See Note 10.a in the 2019 Annual Report for the significant Level 2 inputs for the option pricing model used in the fair value mark-to-market analysis of the contingent consideration. The Company reviewed the third-party specialist's valuations,



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including the related inputs, and analyzed changes in fair values between the reporting dates. See Notes 3.b and 9.b for further discussion of this contingent consideration.

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 three months ended March 31, 2020, pertaining to line-fill and other inventories. There were no comparable impairments of inventory recorded during the three months ended March 31, 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 three months ended March 31, 2020 or 2019.

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 three months ended March 31, 2020, pertaining to midstream service assets. There were no comparable impairments of long-lived assets recorded during the three months ended March 31, 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:



	March 31, 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		240,000		—		—
January 2028 Notes	400,000		152,000		—		—
Senior Secured Credit Facility	275,000		274,540		375,000		375,275
Total	$	1,275,000	$	666,540	$	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 March 31, 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 March 31, 2020 and December 31, 2019.

Note 11—Net income (loss) per common share

Basic net income (loss) per common share is computed by dividing net income (loss) by the weighted-average common shares outstanding for the period. Diluted net income (loss) per common share reflects the potential dilution of non-vested restricted stock awards, outstanding stock option awards, non-vested performance share awards and the non-vested outperformance share award. See Note 8 for additional discussion of these awards. For the three months ended March 31, 2020, the dilutive effects of these awards were calculated utilizing the treasury stock method. For the three months ended March 31, 2019, all of these awards were anti-dilutive due to the Company's net loss and, therefore, were excluded from the calculation of diluted net income (loss) per common share.



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The following table reflects the calculations of basic and diluted (i) weighted-average common shares outstanding and (ii) net income (loss) per common share for the periods presented:



	Three months ended March 31,
(in thousands, except for per share data)	2020		2019
Net income (loss) (numerator)	$	235,095	$	(9,491	)
Weighted-average common shares outstanding (denominator):
Basic	232,351		230,476
Dilutive non-vested restricted stock awards⁽¹⁾	1,107		—
Diluted	233,458		230,476
Net income (loss) per common share:
Basic	$	1.01	$	(0.04	)
Diluted	$	1.01	$	(0.04	)

_____________________________________________________________________________

(1)

The effect of a significant portion of the non-vested restricted stock awards was excluded from the calculation of diluted net income (loss) per common share for the three months ended March 31, 2020. The inclusion of these non-vested restricted stock awards would be anti-dilutive mainly due to the grant-date fair value per common share for the awards being greater than the average closing stock price during the period.

The effect of the outstanding stock option awards was excluded from the calculation of diluted net income (loss) per common share for the three months ended March 31, 2020. The inclusion of these stock option awards would be anti-dilutive as their exercise prices were greater than the average closing stock price during the period.

By assuming March 31, 2020 was the end of the respective performance periods of the non-vested performance share awards and the non-vested outperformance share award, the effects of these awards were excluded from the calculation of diluted net income (loss) per common share for the three months ended March 31, 2020 as the awards were below the respective agreements' payout thresholds, with the exception of the RTSR Performance portion of the 2019 performance share awards and the ROACE-portion of the 2018 and 2019 performance share awards which were ultimately anti-dilutive due to the grant-date fair value per unit being greater than the average closing stock price during the period. See Note 8 for discussion of market and performance criteria of these awards.

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 contracts

The Company has committed to drilling rig contracts with a third party to facilitate the Company's drilling plans. Two of these contracts are for a term of multiple months and contain early termination clauses that require 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 three months ended March 31, 2020 or 2019. As the Company's current drilling rig contracts are operating leases under the scope of ASC 842, the present value of the future commitment as of March 31, 2020 related to the drilling rig contract with an initial term greater than 12 months is included in current and noncurrent operating lease liabilities on the unaudited consolidated balance sheet as of March 31, 2020. The future commitment of $0.3 million as of March 31, 2020 related to a drilling rig contract with an initial term less than 12 months is not recorded in the unaudited consolidated balance sheets. Management does not currently anticipate the early termination of these contracts in 2020. See Note 17 for additional information regarding the drilling rig contracts as they pertain to a related party.



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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. Management anticipates continuing this practice in the future. No firm transportation payments on excess pipeline capacity or other contractual penalties were incurred during the three months ended March 31, 2020. The Company incurred firm transportation payments on excess pipeline capacity and other contractual penalties of $0.5 million during the three months ended March 31, 2019. These firm transportation payments on excess pipeline capacity and other contractual penalties are netted with the respective revenue stream on the unaudited consolidated statements of operations. Future firm sale and transportation commitments of $314.7 million as of March 31, 2020 are not recorded on the unaudited consolidated balance sheets.

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 March 31, 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:



	Three months ended March 31,
(in thousands)	2020		2019
Supplemental cash flow information:
Cash paid for interest, net of $1,181 and $242 of capitalized interest, respectively	$	23,697	$	26,345
Supplemental non-cash investing information:
Increase in accrued capital expenditures	$	16,272	$	6,443
Capitalized share-settled equity-based compensation	$	965	$	1,899
Capitalized asset retirement cost	$	886	$	271

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



	Three months ended March 31,
(in thousands)	2020		2019
Right-of-use assets obtained in exchange for operating lease liabilities⁽¹⁾	$	—	$	22,090

______________________________________________________________________________


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



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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:



	Three months ended March 31,
(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	886			271
Accretion expense	1,106			1,052
Liabilities settled due to plugging and abandonment	(497		)	(447		)
Liability at end of period	$	64,213		$	57,758

Note 15—Revenue recognition

Oil, NGL and natural gas 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 revenue and method 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. The Company had federal net operating loss carryforwards totaling $2.0 billion and state of Oklahoma net operating loss carryforwards totaling $34.7 million as of March 31, 2020, which will begin expiring in 2026 and 2032, respectively. As of March 31, 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 March 31, 2020, the Company's ability to capitalize intangible drilling costs, rather than expensing these costs in order to prevent an operating loss carryforward from expiring unused and future projections of Oklahoma sourced income. As of March 31, 2020, a total valuation allowance of $255.9 million has been recorded to offset the Company's federal and Oklahoma net deferred tax assets, resulting in a Texas net deferred tax liability of $4.9 million, which is included in "Other noncurrent liabilities" 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, 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. The remaining $2.1 million is included in "Accounts receivable, net" on the unaudited consolidated balance sheet as of March 31, 2020.



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Note 17—Related parties

a. Helmerich & Payne, Inc.

The Chairman of the Company's board of directors is on the board of directors of Helmerich & Payne, Inc. ("H&P"). The Company has drilling rig contracts with H&P that are operating leases. During each of the three months ended March 31, 2020 and 2019, the Company has one drilling rig contract that is accounted for as a long-term operating lease under the scope of ASC 842 due to its initial term of greater than 12 months, which is 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 contracts.

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:



	Three months ended March 31,
(in thousands)	2020		2019
Capital expenditures for oil and natural gas properties	$	9,151	$	2,982

b. Halliburton

Beginning in 2020, a member of the Company's board of directors is on the board of directors of Halliburton Company ("Halliburton"). Halliburton provides fracing 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:



	Three months ended
(in thousands)	March 31, 2020
Capital expenditures for oil and natural gas properties	$	27,225

Note 18—Subsequent events

a. Senior Secured Credit Facility

On April 30, 2020, as a result of the semi-annual redetermination, the Company entered into the fourth amendment to the Senior Secured Credit Facility pursuant to which the borrowing base and aggregate elected commitment under the Senior Secured Credit Facility were reduced to $725.0 million each, among other changes.

Additionally, subsequent to March 31, 2020, the Company's outstanding letter of credit was increased to $44.1 million.



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

b. Derivatives

Commodity

The following table summarizes open oil and natural gas derivative positions as of March 31, 2020, for oil and natural gas derivatives that were entered into through May 6, 2020, for the settlement periods presented:



	Remaining year 2020			Year 2021			Year 2022
Oil:
WTI NYMEX - Swaps:
Volume (Bbl)	5,390,000			—			—
Weighted-average price ($/Bbl)	$	59.50		$	—		$	—
Brent ICE:
Puts⁽¹⁾:
Volume (Bbl)	—			2,463,750			—
Weighted-average floor price ($/Bbl)	$	—		$	55.00		$	—
Swaps:
Volume (Bbl)	1,787,500			2,555,000			—
Weighted-average price ($/Bbl)	$	63.07		$	53.19		$	—
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)	1,787,500			5,602,750			—
Weighted-average floor price ($/Bbl)	$	63.07		$	53.13		$	—
Total volume with ceiling (Bbl)	1,787,500			3,139,000			—
Weighted-average ceiling price ($/Bbl)	$	63.07		$	54.37		$	—
Total oil volume with floor (Bbl)	7,177,500			5,602,750			—
Total oil volume with ceiling (Bbl)	7,177,500			3,139,000			—
Basis Swaps:
Brent ICE to WTI NYMEX - Basis Swaps
Volume (Bbl)	2,695,000			—			—
Weighted-average differential ($/Bbl)	$	5.09		$	—		$	—
Natural gas:
Henry Hub NYMEX - Swaps:
Volume (MMBtu)	17,875,000			42,522,500			—
Weighted-average price ($/MMBtu)	$	2.72		$	2.59		$	—
Waha Inside FERC to Henry Hub NYMEX - Basis Swaps:
Volume (MMBtu)	31,625,000			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 paid, which were settled at their respective contracts' inception.

See Note 9 for a table that includes a summary of open NGL derivative positions as of March 31, 2020. There has been no NGL trade activity subsequent to March 31, 2020 through May 6, 2020.



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Interest rate

Due to the inherent volatility in interest rates, the Company has engaged in an interest rate derivative swap transaction 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. 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:



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

The Company did not designate the interest rate derivative a hedge for accounting purposes, and the Company did not enter into such instrument for speculative trading purposes. Accordingly, the changes in fair value will be recognized in earnings.

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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 months ended March 31, 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:



	Three months ended March 31,						2020 compared to 2019
(in thousands)	2020			2019			Change (#)			Change (%)
Oil sales volumes (MBbl)	2,655			2,534			121			5	%
Oil equivalents sales volumes (MBOE)	7,874			6,775			1,099			16	%
Oil, NGL and natural gas sales⁽¹⁾	$	135,885		$	173,376		$	(37,491	)	(22	)%
Net income (loss)	$	235,095		$	(9,491	)	$	244,586		2,577	%
Free Cash Flow (a non-GAAP financial measure)⁽²⁾	$	(57,523	)	$	(50,965	)	$	(6,558	)	(13	)%
Adjusted EBITDA (a non-GAAP financial measure)⁽²⁾	$	116,848		$	122,906		$	(6,058	)	(5	)%

_____________________________________________________________________________


(1)	Our oil, NGL and natural gas sales decreased as a result of a 33% decrease in average sales price per BOE and were partially offset by a 16% increase in MBOE volumes sold.


(2)	See page 44 for discussions regarding and calculations of these non-GAAP financial measures.

Recent developments

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". Federal, state and local authorities have recommended stay-at-home orders and social distancing guidelines for U.S. residents and to avoid all unnecessary travel for any reason including non-essential jobs for an indeterminate amount of time until the spread of COVID-19 declines to acceptable lower levels. Such actions have resulted in a swift and unprecedented reduction in international and U.S. economic activity which, in turn, has adversely affected the demand for oil and natural gas and caused 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. We are responding to these current events with thoughtful planning and are committed to maintaining safe and reliable operations. The health and safety of our employees, suppliers and customers remain a top priority.

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 agree and some producers instead announced planned production increases, after which oil prices declined sharply. By mid-March

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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 go into effect in May 2020, oil prices continued to decline following announcement of the agreement. Further, producers in the U.S. and globally have not reduced oil production at a rate sufficient to match the sharp slowdown in economic activity caused by measures to control the spread of COVID-19, resulting in an oversupply of oil that recently caused WTI oil prices per barrel to fall to -$37 on April 20th.

We maintain an active, multi-year commodity derivatives strategy to minimize commodity price volatility and support cash flows needed for operations. For April through December 2020, we currently have oil derivatives in place for 5.4 million barrels swapped at a weighted-average price of $59.50 WTI per barrel and 1.8 million barrels swapped at a weighted-average price of $63.07 Brent per barrel. We entered into derivatives subsequent to March 31, 2020, and among these, we entered into oil derivatives for 2021 with $50.6 million premiums settled at the respective contracts' inception. For 2021, we currently have oil derivatives in place for 5.6 million barrels at a weighted-average floor price of $53.13 Brent per barrel.

In light of current market conditions, we have taken significant steps to proactively manage our cash flow and preserve liquidity. To prioritize Free Cash Flow, balance sheet strength and returns in a volatile commodity price environment, we reduced expected capital expenditures for 2020 to $290 million from $450 million. We further reduced expected capital expenditures for 2020 to $265 million, driven by additional refinements, including savings for drilling and completions services and postponements of capital projects, with $220 million allocated to drilling and completions activities and $45 million allocated to infrastructure, land and other capitalized costs. Although we have reduced activity dramatically, we are prepared to reduce it further for an extended period if necessary. We will utilize this slowdown to improve on our best in class operations and to continue to reduce expenses to the lowest and most efficient cost structure possible.

Potential Reverse Stock Split and Authorized Share Reduction

On March 17, 2020, our board of directors authorized an amendment to our Certificate of Incorporation to effect, at their discretion, (i) a Reverse Stock Split that will reduce the number of shares of outstanding Common Stock in accordance with a ratio to be determined by our board of directors within a range of 1-for-5 and 1-for-20 currently outstanding and (ii) an Authorized Share Reduction resulting in a decrease from 450,000,000 authorized shares of Common Stock to between 22,500,000 and 90,000,000 authorized shares of Common Stock. The amendments must be approved by stockholders for the board of directors to effect the Reverse Stock Split and the Authorized Share Reduction. We expect the annual meeting of stockholders to be held on May 14, 2020.

Delisting Notice

On March 26, 2020, we received a notice from the NYSE that the average closing price of our shares of Common Stock, over the prior 30-consecutive trading day period was below $1.00 per share, which is the minimum average closing price per share required to maintain continued listing on the NYSE. We have until December 5, 2020 to regain compliance with the minimum share price requirement. If we do not regain compliance, the NYSE will commence suspension and delisting procedures. We intend to consider all available options to regain compliance with the minimum share price requirement, including, if necessary, by implementing the Reverse Stock Split and Authorized Share Reduction.

See Note 7.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of the Reverse Stock Split and Authorized Share Reduction. See "Part II. Item 1A. Risk Factors" included elsewhere in this Quarterly Report.

Senior Secured Credit Facility

On April 30, 2020, as a result of the semi-annual redetermination, we entered into the fourth amendment to our Senior Secured Credit Facility pursuant to which the borrowing base and aggregate elected commitment were reduced to $725.0 million each. Other than the decrease in borrowing base and aggregate elected commitment, among the more significant changes are: (i) 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) the aggregate amount of Asset Dispositions since the Determination Date of the Borrowing Base then in effect was reduced from 10% to 5% of the Borrowing Base then in effect; (iii) the definition of Permitted Investments was modified to eliminate a safe harbor for investments in partnerships and joint ventures and the general "other" safe harbor; and (iv) the definition of Permitted Investment and covenants limiting Distributions and Redemption of Senior Notes were modified such that Investment, Distributions and Redemptions of Senior Notes remain permitted, in each case, so long as immediately after giving effect to such Investment, Distribution or Redemption (a) the amount of Distributions, Investments and Redemptions from and after

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April 1, 2020 is not greater than $100 million, (b) no Default or Event of Default exists, (c) undrawn Commitments are greater than or equal to 35% of Total Commitments, (d) the pro forma ratio of Consolidated Current Assets to Consolidated Current Liabilities is not less than 1.00 to 1.00, and (e) the pro forma Consolidated Total Leverage Ratio is not greater than 2.50 to 1.00. All capitalized terms above have the meanings ascribed to them in the Fourth Amendment or the Senior Secured Credit Facility, as applicable. The Consolidated Total Leverage Ratio of not greater than 4.25 to 1.00 remains unchanged.

Pricing and reserves

Our results of operations are heavily influenced by oil, NGL and natural gas prices, which have experienced significant declines into second-quarter 2020. Oil, NGL and natural gas price fluctuations are currently impacted by the COVID-19 pandemic and policies of OPEC+, which have increased changes in global and regional supply and demand and economic conditions, and caused market uncertainty, transportation and storage constraints and a variety of additional issues. Historically, commodity prices have experienced significant fluctuations; however, the volatility in the prices has substantially increased as a result of the recent 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, 10.a and 18.b to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our commodity derivatives, including those entered into subsequent to March 31, 2020.

Our reserves as of March 31, 2020 and December 31, 2019 are reported in three streams: oil, NGL and natural gas. The Realized Prices utilized to value our proved reserves as of March 31, 2020 and March 31, 2019, were $52.47 per Bbl for oil, $10.47 per Bbl for NGL and $0.28 per Mcf for natural gas, and $56.72 per Bbl for oil, $20.46 per Bbl for NGL and $1.09 per Mcf for natural gas, respectively. 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 and, as such, we recorded a first-quarter non-cash full cost ceiling impairment of $16.7 million. No such impairments were recorded during the three months ended March 31, 2019. As more specifically addressed in "Low commodity price impact on our first-quarter 2020 and potentially on our second-quarter 2020 and Remaining Year 2020 full cost ceiling impairment tests" below, if prices remain at or below the current levels, subject to numerous factors and inherent limitations, and all other factors remain constant, we could incur additional significant non-cash full cost ceiling impairments in the second quarter of 2020 and Remaining Year 2020 (defined below), which will have an adverse effect on our results 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.

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The following table presents our depletion expense for our evaluated oil and natural gas properties per BOE sold for the periods presented:



	Three months ended March 31,				2020 compared to 2019
	2020		2019		Change ($)			Change (%)
Depletion expense per BOE sold	$	7.33	$	8.76	$	(1.43	)	(16	)%

Low commodity price impact on our first-quarter 2020 and potentially on our second-quarter 2020 and Remaining Year 2020 full cost ceiling impairment tests

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.

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 substantial non-cash full cost ceiling impairments in second-quarter 2020 and Remaining Year 2020, which will have an adverse effect on our results 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) government imposed curtailment on 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 are calculations of potential future impairments of our evaluated oil and natural gas properties for the second-quarter 2020 and for the period of April 1 to December 31, 2020 ("Remaining Year 2020"). Such implied impairments 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 second-quarter 2020 and Remaining Year 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 second-quarter 2020 full cost ceiling calculation has been prepared by substituting (i) $43.96 per Bbl for oil, (ii) $7.56 per Bbl for NGL and (iii) $0.38 per Mcf for natural gas (collectively, the "Pro Forma Second-Quarter Prices") for the respective Realized Prices as of March 31, 2020. All other inputs and assumptions have been held constant. Accordingly, this estimation strictly isolates the estimated impact of low commodity prices on the second-quarter 2020 Realized Prices that will be utilized in our full cost ceiling calculation. The Pro Forma Second-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 April 1, 2020 and holding the April 1, 2020 prices constant for the remaining eleventh and twelfth months of the calculation. Based solely on the substitution of the Pro Forma Second-Quarter Prices into our March 31, 2020 proved reserve estimates, the implied second-quarter 2020 impairment would be $448 million.

Our hypothetical Remaining Year 2020 full cost ceiling calculation has been prepared by substituting (i) $34.80 per Bbl for oil, (ii) $5.22 per Bbl for NGL and (iii) $0.88 per Mcf for natural gas (collectively, the "Pro Forma Remaining Year Prices") for the respective Realized Prices. All other inputs and assumptions have been held constant. Accordingly, this estimation strictly

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isolates the estimated impact of low commodity prices on the Remaining Year 2020 Realized Prices that will be utilized in our full cost ceiling calculation. The Pro Forma Remaining Year 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 four months ended April 1, 2020 and using strip pricing as of April 20, 2020 for the Remaining Year 2020. Based solely on the substitution of the Pro Forma Remaining Year Prices into our March 31, 2020 proved reserve estimates, the implied Remaining Year 2020 impairment would be $753 million.

We believe that substituting these prices into our March 31, 2020 proved reserve estimates may help provide users with an understanding of the potential impact on our second-quarter 2020 and Remaining Year 2020 full cost ceiling tests.

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 impairment for the three months ended March 31, 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 March 31, 2020, we had assembled 134,614 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 United States 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, 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 table presents our sources of revenue as a percentage of total revenues:



	Three months ended March 31,				2020 compared to 2019
	2020		2019		Change (#)		Change (%)
Oil sales	59	%	62	%	(3	)%	(5	)%
NGL sales	6	%	15	%	(9	)%	(60	)%
Natural gas sales	2	%	6	%	(4	)%	(67	)%
Midstream service revenues	1	%	1	%	—	%	—	%
Sales of purchased oil	32	%	16	%	16	%	100	%
Total	100	%	100	%

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

The following table presents information regarding our oil, NGL and natural gas sales volumes, sales revenues and average sales prices:



	Three months ended March 31,				2020 compared to 2019
	2020		2019		Change (#)			Change (%)
Sales volumes:
Oil (MBbl)	2,655		2,534		121			5	%
NGL (MBbl)	2,467		2,099		368			18	%
Natural gas (MMcf)	16,512		12,849		3,663			29	%
Oil equivalents (MBOE)⁽¹⁾⁽²⁾	7,874		6,775		1,099			16	%
Average daily oil equivalent sales volumes (BOE/D)⁽²⁾	86,532		75,276		11,256			15	%
Average daily oil sales volumes (Bbl/D)⁽²⁾	29,178		28,157		1,021			4	%
Sales revenues (in thousands):
Oil	$	119,978	$	129,171	$	(9,193	)	(7	)%
NGL	11,558		32,235		(20,677		)	(64	)%
Natural gas	4,349		11,970		(7,621		)	(64	)%
Total oil, NGL and natural gas sales revenues	$	135,885	$	173,376	$	(37,491	)	(22	)%
Average sales prices⁽²⁾:
Oil ($/Bbl)⁽³⁾	$	45.19	$	50.97	$	(5.78	)	(11	)%
NGL ($/Bbl)⁽³⁾	$	4.68	$	15.36	$	(10.68	)	(70	)%
Natural gas ($/Mcf)⁽³⁾	$	0.26	$	0.93	$	(0.67	)	(72	)%
Average sales price ($/BOE)⁽³⁾	$	17.26	$	25.59	$	(8.33	)	(33	)%
Oil, with commodity derivatives ($/Bbl)⁽⁴⁾	$	56.59	$	47.66	$	8.93		19	%
NGL, with commodity derivatives ($/Bbl)⁽⁴⁾	$	6.85	$	15.33	$	(8.48	)	(55	)%
Natural gas, with commodity derivatives ($/Mcf)⁽⁴⁾	$	0.94	$	1.11	$	(0.17	)	(15	)%
Average sales price, with commodity derivatives ($/BOE)⁽⁴⁾	$	23.21	$	24.68	$	(1.47	)	(6	)%

_____________________________________________________________________________


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


(2)	The numbers presented in the three months ended March 31, 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, 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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The following table presents settlements received (paid) 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, presented above:



	Three months ended March 31,						2020 compared to 2019
(in thousands)	2020			2019			Change ($)		Change (%)
Settlements received (paid) for matured commodity derivatives:
Oil	$	31,147		$	(2,095	)	$	33,242	1,587	%
NGL	5,337			(57		)	5,394		9,463	%
Natural gas	11,239			2,254			8,985		399	%
Total	$	47,723		$	102		$	47,621	46,687	%
Premiums paid previously or upon settlement attributable to commodity derivatives that matured during the respective period:
Oil	$	(877	)	$	(6,300	)	$	5,423	86	%

Changes in average sales prices and sales volumes caused the following changes to our oil, NGL and natural gas revenues between the three months ended March 31, 2020 and 2019:



(in thousands)	Oil			NGL			Natural gas			Total
2019 Revenues	$	129,171		$	32,235		$	11,970		$	173,376
Effect of changes in average sales prices	(15,364		)	(26,326		)	(11,034		)	(52,724		)
Effect of changes in sales volumes	6,171			5,649			3,413			15,233
2020 Revenues	$	119,978		$	11,558		$	4,349		$	135,885
Change ($)	$	(9,193	)	$	(20,677	)	$	(7,621	)	$	(37,491	)
Change (%)	(7		)%	(64		)%	(64		)%	(22		)%

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, and decreases are continuing.

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 March 31, 2020, compared to the same period in 2019 is due to an 11% decrease in average oil sales prices and was partially offset by a 5% increase 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 decrease in NGL sales revenue for the three months ended March 31, 2020, compared to the same period in 2019 is due to a 70% decrease in average NGL sales prices and was partially offset by an 18% 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 decrease in natural gas sales revenue for the three months ended March 31, 2020, compared to the same period in 2019 is due to a 72% decrease in average natural gas sales prices and was partially offset by a 29% increase in natural gas sales volumes.

The following table presents midstream service and sales of purchased oil revenues:



	Three months ended March 31,				2020 compared to 2019
(in thousands)	2020		2019		Change ($)			Change (%)
Midstream service revenues	$	2,683	$	2,883	$	(200	)	(7	)%
Sales of purchased oil	$	66,424	$	32,688	$	33,736		103	%

Midstream service revenues. Our midstream service revenues decreased for the three months ended March 31, 2020 compared to the same period 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. These 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

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latter of which we began shipment on during fourth-quarter 2019, and we utilize purchased oil to fulfill portions of our commitments.

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."

Costs and expenses

The following table presents information regarding costs and expenses and selected average costs and expenses per BOE sold:



	Three months ended March 31,				2020 compared to 2019
(in thousands except for per BOE sold data)	2020		2019		Change ($)			Change (%)
Costs and expenses:
Lease operating expenses	$	22,040	$	22,609	$	(569	)	(3	)%
Production and ad valorem taxes	9,244		7,219		2,025			28	%
Transportation and marketing expenses	13,544		4,759		8,785			185	%
Midstream service expenses	1,170		1,603		(433		)	(27	)%
Costs of purchased oil	79,297		32,691		46,606			143	%
General and administrative (excluding LTIP)	10,465		14,392		(3,927		)	(27	)%
General and administrative (LTIP):
LTIP cash	133		192		(59		)	(31	)%
LTIP non-cash	1,964		6,935		(4,971		)	(72	)%
Depletion, depreciation and amortization	61,302		63,098		(1,796		)	(3	)%
Impairment expense	26,250		—		26,250			100	%
Other operating expenses	1,106		1,052		54			5	%
Total costs and expenses	$	226,515	$	154,550	$	71,965		47	%
Selected average costs and expenses per BOE sold⁽¹⁾:
Lease operating expenses	$	2.80	$	3.34	$	(0.54	)	(16	)%
Production and ad valorem taxes	1.17		1.07		0.10			9	%
Transportation and marketing expenses	1.72		0.70		1.02			146	%
Midstream service expenses	0.15		0.24		(0.09		)	(38	)%
General and administrative (excluding LTIP)	1.33		2.12		(0.79		)	(37	)%
Total selected operating expenses	$	7.17	$	7.47	$	(0.30	)	(4	)%
General and administrative (LTIP):
LTIP cash	$	0.02	$	0.03	$	(0.01	)	(33	)%
LTIP non-cash	$	0.25	$	1.02	$	(0.77	)	(75	)%
Depletion, depreciation and amortization	$	7.78	$	9.31	$	(1.53	)	(16	)%

_____________________________________________________________________________


(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 months ended March 31, 2020, compared to the same period in 2019. We continue to focus on economic efficiencies associated with the usage and procurement of products and services related to LOE.

Production and ad valorem taxes. Production and ad valorem taxes increased for the three months ended March 31, 2020, compared to the same period in 2019. We received a $4.5 million production tax refund, related to additional marketing costs claimed for fiscal years 2013 through 2016, recorded during the first quarter of 2019.

Transportation and marketing expenses. Transportation and marketing expenses increased for the three months ended March 31, 2020, compared to the same period in 2019. We recognize transportation and marketing expenses incurred for the

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delivery of produced oil to two 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. Additionally, we recognized $2.0 million in marketing expense due to negative natural gas prices in March 2020.

Midstream service expenses. Midstream service expenses decreased for the three months ended March 31, 2020, compared to the same period 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 months ended March 31, 2020, compared to the same period in 2019. 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 transportation commitments.

General and administrative ("G&A"). G&A, excluding employee compensation expense from our long-term incentive plan ("LTIP"), decreased for the three months ended March 31, 2020, compared to the same period in 2019 mainly due to a decrease in employee-related costs as a result of the measures taken during second-quarter 2019 to align our cost structure with operational activity, which included a workforce reduction. The decrease in cash and non-cash LTIP expense is due to (i) LTIP award forfeitures related to the second-quarter 2019 workforce reduction, which were still being expensed in first-quarter 2019 and (ii) a decrease in LTIP award compensation percentages across our remaining employee base. See Note 8 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for information regarding our equity-based compensation.

Depletion, depreciation and amortization ("DD&A"). The following table presents the components of our DD&A for the periods presented:



	Three months ended March 31,				2020 compared to 2019
(in thousands)	2020		2019		Change ($)			Change (%)
Depletion of evaluated oil and natural gas properties	$	57,752	$	59,370	$	(1,618	)	(3	)%
Depreciation of midstream service assets	2,592		2,501		91			4	%
Depreciation and amortization of other fixed assets	958		1,227		(269		)	(22	)%
Total DD&A	$	61,302	$	63,098	$	(1,796	)	(3	)%

DD&A decreased for the three months ended March 31, 2020, compared to the same period in 2019, mainly due to depletion. Depletion decreased due to the previous increase in our December 31, 2019 proved reserve volume partially offset by an increase in production and an increase in the depletion base, which was mainly due to acquisitions and development and partially offset by full cost impairments. Depletion expense per BOE decreased by $1.43, or 16%, for the three months ended March 31, 2020, compared to the same period in 2019. 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. Our net book value of evaluated oil and natural gas properties exceeded the full cost ceiling as of March 31, 2020, and, as a result, we recorded a full cost ceiling impairment of $16.7 million for the three months ended March 31, 2020. There was no full cost ceiling impairment recorded for the three months ended March 31, 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 discounted future net revenues in the full cost ceiling calculation. In the event the unamortized cost of evaluated oil and natural gas properties being depleted exceeds the full cost ceiling, as defined by the SEC, the excess is 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.

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Additionally, for the three months ended March 31, 2020, we recorded impairment expense of (i) $1.3 million for inventory, pertaining to line-fill and other inventories and (ii) $8.2 million for long-lived assets, pertaining to midstream service assets. There were no comparable impairments of inventory or long-lived assets recorded during the three months ended March 31, 2019. 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, see Note 10.b to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.

Non-operating income (expense)

The following table presents the components of non-operating income (expense), net:



	Three months ended March 31,						2020 compared to 2019
(in thousands)	2020			2019			Change ($)			Change (%)
Gain (loss) on derivatives, net	$	297,836		$	(48,365	)	$	346,201		716	%
Interest expense	(24,970		)	(15,547		)	(9,423		)	(61	)%
Loss on extinguishment of debt	(13,320		)	—			(13,320		)	(100	)%
Loss on disposal of assets, net	(602		)	(939		)	337			36	%
Other income, net	91			867			(776		)	(90	)%
Total non-operating income (expense), net	$	259,035		$	(63,984	)	$	323,019		505	%

Gain (loss) on derivatives, net. The following table presents the changes in the components of gain (loss) on derivatives, net:



	Three months ended March 31,						2020 compared to 2019
(in thousands)	2020			2019			Change ($)		Change (%)
Non-cash gain (loss) on derivatives, net	$	250,590		$	(44,451	)	$	295,041	664	%
Settlements received for matured commodity derivatives, net	47,723			102			47,621		46,687	%
Premiums paid for commodity derivatives	(477		)	(4,016		)	3,539		88	%
Gain (loss) on derivatives, net	$	297,836		$	(48,365	)	$	346,201	716	%

Non-cash gain (loss) on derivatives, net is the result of new, matured and early-terminated contracts 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 or paid for matured derivatives are based on the settlement prices of our matured derivatives compared to the prices specified in the derivative contracts. During the three months ended March 31, 2020, we recognized significant non-cash gains in the net fair value of our derivatives outstanding due to decreases in the applicable futures curves that we have hedged.

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 months ended March 31, 2020, compared to the same period in 2019. This increase is 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 interest rates, partially offset by a decrease in the amount outstanding on our Senior Secured Credit Facility. See Notes 6 and 18.b to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information regarding our debt and our interest rate derivative entered into subsequent to March 31, 2020, respectively.

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 three months ended March 31, 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.

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Loss on disposal of assets, net. Loss on disposal of assets, net, decreased for the three months ended March 31, 2020, compared to the same period in 2019. From time to time, we dispose of inventory, midstream service assets and other fixed assets. The associated gain or loss recorded during the period fluctuates depending upon the volume of the assets disposed, their associated net book value and, in the case of a disposal by sale, the sale price.

Income tax (expense) benefit

The following table presents income tax (expense) benefit for the periods presented:



	Three months ended March 31,					2020 compared to 2019
(in thousands)	2020			2019		Change ($)			Change (%)
Deferred	$	(2,417	)	$	96	$	(2,513	)	(2,618	)%

The deferred income tax (expense) benefit for the periods presented is attributed to deferred Texas franchise tax. We are subject to federal and state income taxes and the Texas franchise tax. As of March 31, 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 March 31, 2020, a total valuation allowance of $255.9 million has been recorded to offset our federal and Oklahoma net deferred tax assets, resulting in a Texas net deferred tax liability of $4.9 million. The effective tax rate for our operations was 1.0% for the three months ended March 31, 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 recent world developments in 2020, we are closely monitoring 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.

A significant portion of our capital expenditures can be adjusted and managed by us. We continually monitor the capital markets and our capital structure and consider which financing alternatives, including equity and debt capital resources, joint ventures and asset sales, are available to meet our future planned capital expenditures. We may make changes to our capital structure from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity and/or achieving cost efficiency. Such financing alternatives, including capital market transactions and, from time to time, debt and equity repurchases, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material. For further discussion of our financing activities related to debt instruments, see Note 6 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report. We continuously look for other opportunities to maximize shareholder value.

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. By removing a portion of the price volatility associated with future sales volumes, we expect to mitigate, but not eliminate, the potential effects of variability in cash flows from operations. See "Part I. Item 3. Quantitative and Qualitative Disclosures About Market Risk" below.

See Note 9 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for discussion of our hedge restructuring during the three months ended March 31, 2020 and corresponding summary of open commodity derivative positions as of March 31, 2020 for commodity derivatives that were entered into through March 31, 2020. Additionally, see Note 18.b for a summary of derivatives that were entered into subsequent to March 31, 2020.

We continually seek to maintain a financial profile that provides operational flexibility. As of March 31, 2020, we had cash and cash equivalents of $62.8 million and available capacity under the Senior Secured Credit Facility, after the reduction for

outstanding letters of credit, of $660.3 million, resulting in total liquidity of $723.1 million. As of May 6, 2020, we had cash and cash equivalents of $5.0 million and available capacity under the Senior Secured Credit Facility, after the reduction for outstanding letters of credit and a reduction in our borrowing base, of $405.9 million, resulting in total liquidity of $410.9 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:



	Three months ended March 31,						2020 compared to 2019
(in thousands)	2020			2019			Change ($)			Change (%)
Net cash provided by operating activities	$	109,589		$	77,458		$	32,131		41	%
Net cash used in investing activities	(159,791		)	(155,453		)	(4,338		)	(3	)%
Net cash provided by financing activities	72,122			77,388			(5,266		)	(7	)%
Net increase (decrease) in cash and cash equivalents	$	21,920		$	(607	)	$	22,527		3,711	%

Cash flows from operating activities

Net cash provided by operating activities increased during the three months ended March 31, 2020, compared to the same period in 2019. Notable cash changes include (i) an increase of $48.2 million in net changes in operating assets and liabilities, (ii) an increase of $51.2 million in settlements received for matured commodity derivatives, net of premiums paid and (iii) a decrease in oil, NGL and natural gas sales revenues of $37.5 million. The decrease in oil, NGL and natural gas sales revenues is due to a 33% decrease in average sales prices per BOE and was partially offset by a 16% increase in total volumes sold. See "—Results of operations" for additional discussion of changes in our oil, NGL and natural gas sales revenues. Other contributing factors are increases for costs of purchased oil and transportation and marketing expenses. See "—Costs and expenses" and "—Non-operating income (expense)" for additional information.

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. Recently, however, commodity prices have been most impacted by the effects of COVID-19 on demand and the effects of the OPEC+ actions and related transportation and storage constraints, particularly in the State of Texas, on supply. These factors are not within our control and are difficult to predict. For additional information on risks related to our business, see "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 increased for the three months ended March 31, 2020, compared to the same period in 2019, mainly due to acquisitions of oil and natural gas properties, partially offset by a decrease in capital expenditures for oil and natural gas properties. See Note 3 to our unaudited consolidated financial statements included elsewhere in the Quarterly Report for additional discussion of our acquisitions of oil and natural gas properties.

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The following table presents the components of our cash flows from investing activities:



	Three months ended March 31,						2020 compared to 2019
(in thousands)	2020			2019			Change ($)			Change (%)
Acquisitions of oil and natural gas properties, net	$	(22,876	)	$	—		$	(22,876	)	(100	)%
Capital expenditures:
Oil and natural gas properties	(135,376		)	(152,729		)	17,353			11	%
Midstream service assets	(761		)	(2,262		)	1,501			66	%
Other fixed assets	(829		)	(505		)	(324		)	(64	)%
Proceeds from dispositions of capital assets, net of selling costs	51			43			8			19	%
Net cash used in investing activities	$	(159,791	)	$	(155,453	)	$	(4,338	)	(3	)%

Cash flows from financing activities

Net cash provided by financing activities decreased for the three months ended March 31, 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, payments on our Senior Secured Credit Facility and payments for debt issuance costs. For further discussion of our financing activities related to debt instruments, see Note 6 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:



	Three months ended March 31,						2020 compared to 2019
(in thousands)	2020			2019			Change ($)			Change (%)
Borrowings on Senior Secured Credit Facility	$	—		$	80,000		$	(80,000	)	(100	)%
Payments on Senior Secured Credit Facility	(100,000		)	—			(100,000		)	(100	)%
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	(640		)	(2,612		)	1,972			75	%
Payments for debt issuance costs	(18,383		)	—			(18,383		)	(100	)%
Net cash provided by financing activities	$	72,122		$	77,388		$	(5,266	)	(7	)%

Expected capital expenditures

Our goal is to achieve positive Free Cash Flow in 2020 and, therefore, our capital spending in 2020 will ultimately be influenced by commodity price changes, production levels and, among other factors, changes in service costs and drilling and completions efficiencies. Due to the significant decrease in oil, NGL and natural gas prices, we adjusted our expected capital expenditures, excluding non-budgeted acquisitions, to $265.0 million for calendar year 2020. We are prepared to decrease our capital expenditures further if oil, NGL and natural gas prices remain weak. We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted.

The following table presents the components of our costs incurred, excluding non-budgeted acquisition costs:



	Three months ended March 31,				2020 compared to 2019
(in thousands)	2020		2019		Change ($)			Change (%)
Oil and natural gas properties⁽¹⁾	$	152,868	$	160,222	$	(7,354	)	(5	)%
Midstream service assets	923		3,373		(2,450		)	(73	)%
Other fixed assets	823		514		309			60	%
Total costs incurred, excluding non-budgeted acquisition costs	$	154,614	$	164,109	$	(9,495	)	(6	)%

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(1)	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.

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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 consistently 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.

Debt

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 March 31, 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 $950.0 million each, with $275.0 million outstanding and was subject to an interest rate of 2.43%. 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 March 31, 2020 and December 31, 2019, we had one letter of credit outstanding of $14.7 million under the Senior Secured Credit Facility. The Senior Secured Credit Facility is fully and unconditionally guaranteed by LMS and GCM.

Additionally, subsequent to March 31, 2020, our outstanding letter of credit was increased to $44.1 million.

January 2025 Notes and January 2028 Notes

The following table presents principal amounts and applicable interest rates for our outstanding Senior Unsecured Notes as of March 31, 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 (together the "Senior Unsecured Notes"). As of March 31, 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

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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

The following table presents significant contractual obligations and commitments as of March 31, 2020 and December 31, 2019 and their associated changes:



($ in thousands, except % change)	March 31, 2020		December 31, 2019		Change ($)			Change (%)
Senior Unsecured Notes⁽¹⁾	$	1,606,563	$	939,844	$	666,719		71	%
Firm sale and transportation commitments⁽²⁾	314,741		322,790		(8,049		)	(2	)%
Senior Secured Credit Facility⁽³⁾	275,000		375,000		(100,000		)	(27	)%
Asset retirement obligations⁽⁴⁾	64,213		62,718		1,495			2	%
Lease commitments⁽⁵⁾	30,590		35,606		(5,016		)	(14	)%
Commodity derivative deferred premiums⁽⁶⁾	—		477		(477		)	(100	)%
Total	$	2,291,107	$	1,736,435	$	554,672		32	%

____________________________________________________________________________

(1)

Values presented include both our principal and interest obligations. The increase in such balance as of March 31, 2020 is due to (i) the issuance of our January 2025 Notes and January 2028 Notes, (ii) the extinguishment of our January 2022 Notes and March 2023 Notes and (iii) an increase in our interest rates as a result of such financing transactions. See Notes 6.a and 6.b to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our Senior Unsecured Notes.

(2)

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. The decrease in such commitments as of March 31, 2020 is mainly due to our fulfillment of contractual commitments, partially offset by changes to existing sales commitments. 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.

(3)

This table does not include future loan advances, repayments, commitment fees or other fees on our Senior Secured Credit Facility as we cannot determine with accuracy the timing of such items. Additionally, this table does not include interest expense as it is a floating rate instrument and we cannot determine with accuracy the future interest rates to be charged. The decrease in such balance as of March 31, 2020 is due to our repayments. As of March 31, 2020, the principal on our Senior Secured Credit Facility is due on April 19, 2023.


(4)	Amounts represent our asset retirement obligation liabilities. See Note 14 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our asset retirement obligations.


(5)	Amounts represent our minimum lease payments. The decrease in lease commitments as of March 31, 2020 is mainly due to the settlements paid for our fulfillment of lease commitments. See Note 5 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our leases.


(6)	Amounts represent payments required for deferred premiums on our commodity derivative contracts. The decrease in premiums as of March 31, 2020 is due to premiums paid for commodity derivatives. See Note 10.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our deferred premiums.

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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):



	Three months ended March 31,
(in thousands)	2020			2019
Net cash provided by operating activities	$	109,589		$	77,458
Less:
Change in current assets and liabilities, net	18,708			(36,750		)
Change in noncurrent assets and liabilities, net	(6,210		)	1,064
Cash flows from operating activities before changes in operating assets and liabilities, net	97,091			113,144
Less costs incurred, excluding non-budgeted acquisition costs⁽¹⁾:
Oil and natural gas properties	152,868			160,222
Midstream service assets	923			3,373
Other fixed assets	823			514
Total costs incurred, excluding non-budgeted acquisition costs	154,614			164,109
Free Cash Flow (non-GAAP)	$	(57,523	)	$	(50,965	)

_____________________________________________________________________________


(1)	Includes capitalized share-settled equity-based compensation of $1.0 million and $1.9 million and asset retirement costs of $0.4 million and $0.3 million for the three months ended March 31, 2020 and 2019, respectively.

Adjusted EBITDA

Adjusted EBITDA is a non-GAAP financial measure that we define as net income or loss plus adjustments for net share-settled equity-based compensation, depletion, depreciation and amortization, impairment expense, mark-to-market on derivatives, premiums paid for commodity derivatives, accretion expense, gains or losses on disposal of assets, 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;

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


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

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

The following table presents a reconciliation of net income (loss) (GAAP) to Adjusted EBITDA (non-GAAP):



	Three months ended March 31,
(in thousands)	2020			2019
Net income (loss)	$	235,095		$	(9,491	)
Plus:
Share-settled equity-based compensation, net	2,376			7,406
Depletion, depreciation and amortization	61,302			63,098
Impairment expense	26,250			—
Mark-to-market on derivatives:
(Gain) loss on derivatives, net	(297,836		)	48,365
Settlements received for matured commodity derivatives, net	47,723			102
Premiums paid for commodity derivatives	(477		)	(4,016		)
Accretion expense	1,106			1,052
Loss on disposal of assets, net	602			939
Interest expense	24,970			15,547
Loss on extinguishment of debt	13,320			—
Income tax expense (benefit)	2,417			(96		)
Adjusted EBITDA	$	116,848		$	122,906

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 three months ended March 31, 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 derivative positions are largely determined by the relevant forward commodity price curves of the indexes associated with our open positions. We had a $319.1 million total asset position from the net fair values of our open commodity derivatives and a $0.9 million liability position from the potential contingent consideration associated with an asset acquisition, each as of March 31, 2020. The following table provides a sensitivity analysis of the projected incremental effect on income (loss) before income taxes of a hypothetical 10% change in the relevant forward commodity price curves of the indexes associated with our open derivative positions as of March 31, 2020:



(in thousands)	10% Increase			10% Decrease
Commodity	$	(42,831	)	$	45,618
Contingent consideration	(295		)	265
Total	$	(43,126	)	$	45,883

See Notes 9, 10.a and 18.b to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of our derivatives, including those entered into subsequent to March 31, 2020.

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 March 31, 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	$	275.0		$	—		$	—
Floating interest rate	2.426		%	—		%	—		%

See Notes 6, 10.c and 18.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of our debt. See Note 18.b to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for discussion of our interest rate swap derivative entered into subsequent to March 31, 2020.

Counterparty and customer credit risk

We use commodity derivatives to hedge our exposure to oil, NGL and natural gas price volatility. These transactions expose us to potential credit risk from our counterparties. We have entered into International Swap Dealers Association Master Agreements ("ISDA Agreements") with each of our commodity derivative counterparties, each of whom is also a lender in our Senior Secured Credit Facility, which is secured by our oil, NGL and natural gas reserves; therefore, we are not required to post any collateral. We do not require collateral from our commodity 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

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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 derivative counterparties is somewhat mitigated. We minimize the credit risk in commodity derivatives by: (i) limiting our exposure to any single counterparty, (ii) entering into commodity 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 $319.1 million and $75.3 million total asset position from the net fair values of our open commodity derivative contracts as of March 31, 2020 and December 31, 2019, respectively. See Notes 9, 10.a and 18.b to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for discussion of our commodity 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 generally made to one to two 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 "Part II, Item 1. Legal Proceedings" and Note 12 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for discussion of commitments and contingencies. See Note 2.e in the 2019 Annual Report for discussion of our accounts receivable. See Note 15 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for discussion of revenue recognition.

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 officer and principal financial officer. Based on that evaluation, these officers concluded that Laredo's disclosure controls and procedures were effective as of March 31, 2020. Our disclosure controls and other procedures are designed to provide reasonable assurance that the information required to be disclosed in the reports we file and submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to Laredo's management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

Evaluation of changes in internal control over financial reporting

There were no changes in our internal control over financial reporting during the quarter ended March 31, 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.

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. 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 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 and as such, we recorded a non-cash full cost ceiling impairment of $16.7 million for the three months ended March 31, 2020. We recorded a non-cash full cost ceiling impairment of $620.6 million for the year ended December 31, 2019. 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 second quarter of 2020 and Remaining Year 2020, which will have an adverse effect on our results of operations. See "Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent developments" 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 business and operations have been and will likely continue to be adversely affected by the recent COVID-19 pandemic and responses

The spread of the COVID-19 coronavirus caused, and is continuing to cause, severe disruptions in the worldwide and U.S. economy, including the global and domestic decreased demand for oil and natural gas, which has had an adverse effect on our business, financial condition and results of operations. Moreover, since the beginning of January 2020, the COVID-19 pandemic has caused significant disruption in the financial markets both globally and in the United States. The continued spread of the COVID-19 coronavirus could also negatively impact the availability of key personnel necessary to conduct our business. If the COVID-19 coronavirus continues to spread or the response to contain the COVID-19 pandemic is unsuccessful, we could continue to experience a material adverse effect on our business, financial condition and results of operations.

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 customer's 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.

Due to the rapid development and fluidity of this situation, we cannot make any prediction as to the ultimate material adverse impact of the COVID-19 pandemic on our business, financial condition and results of operations.

The sharp decline in oil and natural gas prices and continued volatility in the oil and natural gas markets have negatively impacted, and are likely to continue to negatively impact, our exploration and production activities and, as a result, our financial condition and results of operations.

Oil prices have declined sharply since March 2020 as a result of multiple factors affecting levels of supply and demand in global oil and gas markets, including the announcement of price reductions and production increases by OPEC+ as well as pipeline capacity and storage constraints created by excess oil supply in the Permian Basin and the COVID-19 pandemic. Oil and natural gas prices are expected to continue to be volatile as a result of the extent and duration of global production increases, the lack of storage capacity in Texas and the ongoing COVID-19 pandemic and as changes in oil and natural gas inventories, production curtailments, decreased industry demand and negative national and global economic performance are reported, and we cannot predict when prices will improve and stabilize.

Worldwide and U.S. political and economic developments, including the outcome of the U.S. presidential election and resulting energy, monetary, trade and environmental policies, and military events, as well as natural disasters and global or national health pandemics, such as COVID-19, epidemics or concerns and other factors beyond our control contribute to oil and natural gas price levels and volatility and are likely to continue to do so in the future. Current levels in the price of oil, NGL and natural gas, as well as ongoing volatility, have had an adverse impact on the level of our budgeted capital expenditures, drilling and exploration and production activity and may force us to shut-in production of a portion or all of our wells that require significant costs to restart, which could continue to materially and adversely affect us, and we cannot predict the ultimate impact of this situation on, business, financial condition and results of operations.

The duration and extent to which the COVID-19 crisis and oil price volatility adversely affects our business, results or operations and financial condition will depend on future developments, which are highly uncertain and cannot be predicted, including the scope and duration of the pandemic and actions taken by oil producing countries, governmental authorities and other third parties in response.

Risks relating to our common stock

If our common stock is delisted from the NYSE, our business, financial condition, results of operations and stock price could be adversely affected, and the liquidity of our stock and our ability to obtain financing could be impaired.

On March 26, 2020, we received a notice from the NYSE that the average closing price of our shares of common stock, par value $0.01 per share ("Common Stock"), over the prior 30-consecutive trading day period was below $1.00 per share, which is the minimum average closing price per share required to maintain listing on the NYSE. We have until December 5, 2020 to regain compliance with the minimum share price requirement. If we do not regain compliance, the NYSE will commence suspension and delisting procedures.

Our board of directors has proposed that our stockholders approve at our 2020 Annual Meeting of Stockholders expected to be held on May 14, 2020 (i) a reverse stock split (the "Reverse Stock Split") that will reduce the number of shares of outstanding Common Stock in accordance with a ratio to be determined by our 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 (the "Authorized Share Reduction"). Notwithstanding approval of this proposal by our stockholders, our board of directors will have the sole authority to elect whether or not and when to amend our certificate of incorporation to effect the Reverse Stock Split and the Authorized Share Reduction.

If approved by our board of directors, there can be no assurance that upon any such implementation of the Reverse Stock Split that we will regain compliance and that our common stock will remain listed on the NYSE. Any delisting of our common stock from the NYSE could adversely affect our ability to attract new investors, decrease the liquidity of our outstanding shares of common stock, reduce our flexibility to raise additional capital, reduce the price at which our common stock trades, and increase the transaction costs inherent in trading such shares with overall negative effects for our stockholders. In addition, the delisting of our common stock could deter broker-dealers from making a market in or otherwise seeking or generating interest in our common stock, and might deter certain institutions and persons from investing in our securities at all. For these reasons and others, the delisting of our common stock from the NYSE could materially adversely affect our business, financial condition and results of operations.

We cannot assure you that our proposed Reverse Stock Split will increase our stock price, marketability or our liquidity.

While we expect that the Reverse Stock Split, if approved and implemented, will increase the market price of our Common Stock, it is possible that it will not. Some investors may view a reverse stock split negatively. We cannot assure you that, if implemented, our Common Stock will be more attractive to institutional or other long term investors or that it will attract brokers and investors who trade in lower priced stocks. Even if we implement the Reverse Stock Split, the market price and liquidity of our Common Stock may decrease due to other factors, including the oil and gas market and our future performance. The percentage market price decline as an absolute number and as a percentage of our overall market capitalization may be greater than would occur in the absence of the Reverse Stock Split. In addition, if the Reverse Stock Split is implemented, it will increase the number of our stockholders who own "odd lots" of fewer than 100 shares of Common Stock. Brokerage commission and other costs of transactions in odd lots are generally higher than the costs of transactions of more than 100 shares of Common Stock. Accordingly, the Reverse Stock Split may not achieve the desired results of increasing the stock price, marketability and liquidity of our Common Stock, which could materially adversely affect our business, financial condition and 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⁽²⁾
January 1, 2020 - January 31, 2020	—	$	—	—	$	102,945,283
February 1, 2020 - February 29, 2020	523,836	$	1.22	—	$	—
March 1, 2020 - March 31, 2020	—	$	—	—	$	—
Total	523,836			—

______________________________________________________________________________


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

(2)

In February 2018, our board of directors authorized a $200 million share repurchase program commencing in February 2018. Share repurchases under the share repurchase program could be made through a variety of methods, which may include open market purchases, privately negotiated transactions and block trades. The timing and actual number of shares repurchased, depended upon several factors, including market conditions, business conditions, the trading price of our common stock and the nature of other investment opportunities available to us. The repurchase program expired in February 2020.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

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Item 5. Other Information

Disclosures required pursuant to Section 13(r) of the Securities Exchange Act of 1934

Pursuant to Section 13(r) of the Exchange Act, we are required to include certain disclosures in our periodic reports if we or any of our "affiliates" (as defined in Rule 12b-2 under the Exchange Act) knowingly engaged in certain specified activities, transactions or dealings relating to Iran or with certain individuals or entities targeted by United States' economic sanctions during the period covered by the report. Disclosure is generally required even where the activities, transactions or dealings were conducted in compliance with applicable law. Neither we nor any of our controlled affiliates or subsidiaries knowingly engaged in any of the specified activities relating to Iran or otherwise engaged in any activities associated with Iran during the reporting period. However, because the SEC defines the term "affiliate" broadly, it includes any entity controlled by us as well as any person or entity that controlled us or is under common control with us.

The description of the activities below has been provided to us by Warburg Pincus LLC ("Warburg Pincus"), affiliates of which: (i) beneficially own more than 10% of our outstanding common stock and are members of 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 us; 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 Warburg Pincus and does not involve our or Warburg Pincus' management. Neither Laredo nor Warburg Pincus had any involvement in or control over the disclosed activities of EIGI, and neither Laredo nor Warburg Pincus has independently verified or participated in the preparation of the disclosure. Neither Laredo nor Warburg Pincus is representing as to the accuracy or completeness of the disclosure nor do we or Warburg Pincus undertake any obligation to correct or update it.

Laredo understands that EIGI intends to disclose in its next annual or quarterly SEC report that:

On January 24, 2020, EIGI's subsidiary MyDomain, LLC ("MyDomain") suspended the domain names FarsNews.com, FarsNews.org and FarsNews.net (the "FarsNews Domain Names"), which are potentially associated with the Government of Iran. MyDomain's records indicate that it collected a total of USD two-hundred sixteen dollars and eighty-four cents ($216.84) for products and services in connection with the subscriber account associated with the Farsnews Domain Names since the subscriber account was migrated to EIGI's servers on or about August 10, 2012, following EIGI's acquisition of MyDomain on July 22, 2011. MyDomain reported the FarsNews Domain Names to the Office of Foreign Assets Control as property potentially associated with the Government of Iran subject to blocking pursuant to 31 C.F.R. Part 560.

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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 Ownership and Merger, dated as of December 30, 2013.	8-K	3.1	1/6/2014
3.3	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
4.2	Indenture, dated as of January 23, 2014, among Laredo Petroleum, Inc., Laredo Midstream Services, LLC and Wells Fargo Bank, N.A., as trustee.	8-K	4.1	1/24/2014
4.3	First Supplemental Indenture, dated as of December 3, 2014, among Laredo Petroleum, Inc., Garden City Minerals, LLC, Laredo Midstream Services, LLC and Wells Fargo Bank, N.A., as trustee.	10-K	4.9	2/26/2015
4.4	Second Supplemental Indenture, dated as of January 22, 2020, among Laredo Petroleum, Inc., Laredo Midstream Services, LLC, Garden City Minerals, LLC and Wells Fargo Bank, National Association, as trustee.	8-K	4.2	1/24/2020
4.5	Indenture, dated as of March 18, 2015, among Laredo Petroleum, Inc., Laredo Midstream Services, LLC, Garden City Minerals, LLC and Wells Fargo Bank, N.A., as trustee.	8-K	4.1	3/24/2015
4.6	First Supplemental Indenture, dated as of March 18, 2015, among Laredo Petroleum, Inc., Laredo Midstream Services, LLC, Garden City Minerals, LLC and Wells Fargo Bank, N.A., as trustee.	8-K	4.2	3/24/2015
4.7	Second Supplemental Indenture, dated as of January 22, 2020, among Laredo Petroleum, Inc., Laredo Midstream Services, LLC, Garden City Minerals, LLC and Wells Fargo Bank, N.A., as trustee.	8-K	4.3	1/24/2020
4.8	Third Supplemental Indenture, dated as of January 24, 2020, among Laredo Petroleum, Inc., Laredo Midstream Services, LLC, Garden City Minerals, LLC and Wells Fargo Bank, N.A., as trustee.	8-K	4.4	1/24/2020
4.9	Fourth Supplemental Indenture, dated as of January 24, 2020, among Laredo Petroleum, Inc., Laredo Midstream Services, LLC, Garden City Minerals, LLC and Wells Fargo Bank, N.A., as trustee.	8-K	4.6	1/24/2020
10.1	Schedule 1, amended and restated as of January 22, 2020, to the Third Amendment to the Fifth Amended and Restated Credit Agreement, dated as of April 19, 2018, 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.	10-K	10.5	2/13/2020
10.2#	Laredo Petroleum, Inc. Executive Severance Plan.	8-K	10.1	2/26/2020
10.3	Fourth Amendment to Fifth Amended and Restated Credit Agreement, dated as of April 30, 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	5/6/2020
22.1*	List of Issuers and Guarantor Subsidiaries
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 March 31, 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.


#	Management contract or compensatory plan or arrangement.

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SIGNATURES

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



	LAREDO PETROLEUM, INC.

Date: May 7, 2020	By:	/s/ Jason Pigott
		Jason Pigott
		President and Chief Executive Officer
		(principal executive officer)

Date: May 7, 2020	By:	/s/ Michael T. Beyer
		Michael T. Beyer
		Senior Vice President and Chief Financial Officer
		(principal financial officer & principal accounting officer)