10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended June 30, 2016

or

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

For the transition period from                             to                            

Commission File Number: 001-35380

Laredo Petroleum, Inc.

(Exact Name of Registrant as Specified in Its Charter)

Delaware  (State or Other Jurisdiction of Incorporation or Organization) 45-3007926  (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)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý  No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý  No o

     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. 

Large accelerated filer ý	Accelerated filer o
Non-accelerated filer o	Smaller reporting company o
(Do not check if a smaller reporting company)

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

Number of shares of registrant's common stock outstanding as of August 1, 2016: 240,124,869

TABLE OF CONTENTS

		Page
Cautionary Statement Regarding Forward-Looking Statements		iii
	Part I
Item 1.	Consolidated Financial Statements (Unaudited)	1
	Consolidated balance sheets as of June 30, 2016 and December 31, 2015	1
	Consolidated statements of operations for the three and six months ended June 30, 2016 and 2015	2
	Consolidated statement of stockholders' equity for the six months ended June 30, 2016	3
	Consolidated statements of cash flows for the six months ended June 30, 2016 and 2015	4
	Condensed notes to the consolidated financial statements	5
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	40
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	58
Item 4.	Controls and Procedures	60
	Part II
Item 1.	Legal Proceedings	61
Item 1A.	Risk Factors	61
Item 2.	Repurchase of Equity Securities	61
Item 3.	Defaults Upon Senior Securities	61
Item 4.	Mine Safety Disclosures	61
Item 5.	Other Information	61
Item 6.	Exhibits	63
Signatures		64
Exhibit Index		65

ii

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 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, and substantial decline in, oil, natural gas liquids ("NGL") and natural gas prices, which remain at low levels;

• revisions to our reserve estimates as a result of changes in commodity prices and uncertainties;

• impacts to our financial statements as a result of impairment write-downs;

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

• uncertainties about the estimates of our oil, NGL and natural gas reserves;

• changes in domestic and global production, supply and demand for oil, NGL and natural gas;

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

• capital requirements for our operations and projects;

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

• restrictions contained in our debt agreements, including our Senior Secured Credit Facility and the indentures governing our senior unsecured notes, as well as debt that could be incurred in the future;

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

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

• regulations that prohibit or restrict our ability to apply hydraulic fracturing to our oil and natural gas wells and to access and dispose of water used in these operations;

• legislation or regulations that prohibit or restrict our ability to drill new allocation wells;

• our ability to execute our strategies, including but not limited to our hedging strategies;

• competition in the oil and natural gas industry;

• changes in the regulatory environment and changes in international, legal, political, administrative or economic conditions;

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

• risks related to the geographic concentration of our assets;

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

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

iii

• the 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 comply with federal, state and local regulatory requirements; and

• our ability to recruit and retain the qualified personnel necessary to operate our business.

These forward-looking statements involve a number of risks and uncertainties that could cause actual results to differ materially from those suggested by the forward-looking statements. Forward-looking statements should, therefore, be considered in light of various factors, including those set forth under "Part I, Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations" and elsewhere in this Quarterly Report, under "Part I, Item 1A. Risk Factors" and "Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015 (the "2015 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.

iv

PART I

Item 1.    Consolidated Financial Statements (Unaudited)

Laredo Petroleum, Inc.

Consolidated balance sheets

(in thousands, except share data)

(Unaudited)

	June 30, 2016			December 31, 2015
Assets
Current assets:
Cash and cash equivalents	$	19,309		$	31,154
Accounts receivable, net	88,543			87,699
Derivatives	88,965			198,805
Other current assets	14,445			14,574
Total current assets	211,262			332,232
Property and equipment:
Oil and natural gas properties, full cost method:
Evaluated properties	5,309,151			5,103,635
Unevaluated properties not being depleted	114,507			140,299
Less accumulated depletion and impairment	(4,448,482		)	(4,218,942		)
Oil and natural gas properties, net	975,176			1,024,992
Midstream service assets, net	128,052			131,725
Other fixed assets, net	40,951			43,538
Property and equipment, net	1,144,179			1,200,255
Derivatives	32,680			77,443
Investment in equity method investee	213,616			192,524
Other assets, net	8,414			10,833
Total assets	$	1,610,151		$	1,813,287
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable	$	14,500		$	14,181
Undistributed revenue and royalties	25,452			34,540
Accrued capital expenditures	39,860			61,872
Derivatives	1,480			—
Other current liabilities	72,520			106,222
Total current liabilities	153,812			216,815
Long-term debt, net	1,392,877			1,416,226
Derivatives	3,740			—
Asset retirement obligations	46,716			44,759
Other noncurrent liabilities	3,844			4,040
Total liabilities	1,600,989			1,681,840
Commitments and contingencies
Stockholders’ equity:
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued as of June 30, 2016 and December 31, 2015	—			—
Common stock, $0.01 par value, 450,000,000 shares authorized and 227,197,566 and 213,808,003 issued and outstanding as of June 30, 2016 and December 31, 2015, respectively	2,272			2,138
Additional paid-in capital	2,216,036			2,086,652
Accumulated deficit	(2,209,146		)	(1,957,343		)
Total stockholders’ equity	9,162			131,447
Total liabilities and stockholders’ equity	$	1,610,151		$	1,813,287

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

1

Laredo Petroleum, Inc.

Consolidated statements of operations

(in thousands, except per share data)

(Unaudited)

	Three months ended June 30,						Six months ended June 30,
	2016			2015			2016			2015
Revenues:
Oil, NGL and natural gas sales	$	102,526		$	125,554		$	175,668		$	243,672
Midstream service revenues	1,632			1,726			3,433			3,035
Sales of purchased oil	42,615			55,051			74,229			86,318
Total revenues	146,773			182,331			253,330			333,025
Costs and expenses:
Lease operating expenses	19,225			29,206			39,743			61,586
Production and ad valorem taxes	7,982			9,500			14,417			18,586
Midstream service expenses	1,178			1,597			1,787			3,171
Minimum volume commitments	—			3,579			—			5,235
Costs of purchased oil	44,012			54,417			76,958			85,617
General and administrative	20,502			23,208			39,953			45,063
Restructuring expenses	—			—			—			6,042
Accretion of asset retirement obligations	860			593			1,704			1,172
Depletion, depreciation and amortization	34,177			72,112			75,655			144,054
Impairment expense	963			489,599			162,027			490,477
Total costs and expenses	128,899			683,811			412,244			861,003
Operating income (loss)	17,874			(501,480		)	(158,914		)	(527,978		)
Non-operating income (expense):
Loss on derivatives, net	(68,518		)	(63,899		)	(50,633		)	(744		)
Income from equity method investee	3,696			2,914			5,994			2,481
Interest expense	(23,512		)	(23,970		)	(47,217		)	(56,384		)
Interest and other income	11			173			110			296
Loss on early redemption of debt	—			(31,537		)	—			(31,537		)
Write-off of debt issuance costs	(842		)	—			(842		)	—
Loss on disposal of assets, net	(141		)	(1,081		)	(301		)	(1,843		)
Non-operating expense, net	(89,306		)	(117,400		)	(92,889		)	(87,731		)
Loss before income taxes	(71,432		)	(618,880		)	(251,803		)	(615,709		)
Income tax benefit:
Deferred	—			221,846			—			218,203
Total income tax benefit	—			221,846			—			218,203
Net loss	$	(71,432	)	$	(397,034	)	$	(251,803	)	$	(397,506	)
Net loss per common share:
Basic	$	(0.33	)	$	(1.88	)	$	(1.17	)	$	(2.13	)
Diluted	$	(0.33	)	$	(1.88	)	$	(1.17	)	$	(2.13	)
Weighted-average common shares outstanding:
Basic	217,564			211,078			214,562			186,886
Diluted	217,564			211,078			214,562			186,886

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

2

Laredo Petroleum, Inc.

Consolidated statement of stockholders' equity

(in thousands)

(Unaudited)

	Common Stock					Additional paid-in capital			Treasury Stock (at cost)					Accumulated deficit
	Shares		Amount						Shares		Amount						Total
Balance, December 31, 2015	213,808		$	2,138		$	2,086,652		—		$	—		$	(1,957,343	)	$	131,447
Restricted stock awards	2,968		30			(30		)	—		—			—			—
Restricted stock forfeitures	(221	)	(2		)	2			—		—			—			—
Vested restricted stock exchanged for tax withholding	—		—			—			288		(1,541		)	—			(1,541		)
Retirement of treasury stock	(288	)	(3		)	(1,538		)	(288	)	1,541			—			—
Exercise of employee stock options	6		—			67			—		—			—			67
Equity issuance, net of offering costs	10,925		109			119,201			—		—			—			119,310
Stock-based compensation	—		—			11,682			—		—			—			11,682
Net loss	—		—			—			—		—			(251,803		)	(251,803		)
Balance, June 30, 2016	227,198		$	2,272		$	2,216,036		—		$	—		$	(2,209,146	)	$	9,162

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

3

Laredo Petroleum, Inc.

Consolidated statements of cash flows

(in thousands)

(Unaudited)

	Six months ended June 30,
	2016			2015
Cash flows from operating activities:
Net loss	$	(251,803	)	$	(397,506	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Deferred income tax benefit	—			(218,203		)
Depletion, depreciation and amortization	75,655			144,054
Impairment expense	162,027			490,477
Loss on early redemption of debt	—			31,537
Non-cash stock-based compensation, net of amounts capitalized	9,911			11,056
Mark-to-market on derivatives:
Loss on derivatives, net	50,633			744
Cash settlements received for matured derivatives, net	113,319			109,737
Cash settlements received for early terminations of derivatives, net	80,000			—
Change in net present value of deferred premiums paid for derivatives	133			88
Cash premiums paid for derivatives	(84,263		)	(2,670		)
Amortization of debt issuance costs	2,187			2,501
Write-off of debt issuance costs	842			—
Income from equity method investee	(5,994		)	(2,481		)
Cash settlement of performance unit awards	(6,394		)	(2,738		)
Other, net	2,009			3,012
(Increase) decrease in accounts receivable	(844		)	16,586
Increase in other assets	(117		)	(9,097		)
Increase (decrease) in accounts payable	319			(15,744		)
Decrease in undistributed revenues and royalties	(9,088		)	(20,699		)
Increase (decrease) in other accrued liabilities	295			(28,341		)
(Decrease) increase in other noncurrent liabilities	(196		)	318
Increase in fair value of performance unit awards	—			1,674
Net cash provided by operating activities	138,631			114,305
Cash flows from investing activities:
Capital expenditures:
Oil and natural gas properties	(197,042		)	(374,508		)
Midstream service assets	(3,425		)	(34,137		)
Other fixed assets	(832		)	(6,541		)
Investment in equity method investee	(42,681		)	(14,495		)
Proceeds from dispositions of capital assets, net of costs	350			35
Net cash used in investing activities	(243,630		)	(429,646		)
Cash flows from financing activities:
Borrowings on Senior Secured Credit Facility	120,000			300,000
Payments on Senior Secured Credit Facility	(144,682		)	(475,000		)
Issuance of March 2023 Notes	—			350,000
Redemption of January 2019 Notes	—			(576,200		)
Proceeds from issuance of common stock, net of offering costs	119,310			754,163
Purchase of treasury stock	(1,541		)	(2,591		)
Proceeds from exercise of employee stock options	67			—
Payments for debt issuance costs	—			(6,759		)
Net cash provided by financing activities	93,154			343,613
Net (decrease) increase in cash and cash equivalents	(11,845		)	28,272
Cash and cash equivalents, beginning of period	31,154			29,321
Cash and cash equivalents, end of period	$	19,309		$	57,593

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

4

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Note 1—Organization

Laredo Petroleum, Inc. ("Laredo"), together with its subsidiaries, Laredo Midstream Services, LLC ("LMS") and Garden City Minerals, LLC ("GCM"), is an independent energy company focused on the acquisition, exploration and development of oil and natural gas properties, and the transportation of oil and natural gas from such properties, primarily in the Permian Basin in West Texas. LMS and GCM (together, the "Guarantors") guarantee all of Laredo's debt instruments. 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.

The Company operates in two business segments: (i) exploration and production and (ii) midstream and marketing. The exploration and production segment is engaged in the acquisition, exploration and development of oil and natural gas properties primarily in the Permian Basin in West Texas. The midstream and marketing segment provides Laredo's exploration and production segment and third parties with products and services that need to be delivered by midstream infrastructure, including oil and natural gas gathering services as well as rig fuel, natural gas lift and water delivery and takeaway in and around Laredo's primary production corridors.

Note 2—Basis of presentation and significant accounting policies

a.    Basis of presentation

The accompanying unaudited consolidated financial statements were derived from the historical accounting records of the Company and reflect the historical financial position, results of operations and cash flows for the periods described herein. The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). All material intercompany transactions and account balances have been eliminated in the consolidation of accounts. The Company uses the equity method of accounting to record its net interests when the Company holds 20% to 50% of the voting rights and/or has the ability to exercise significant influence but does not control the entity. Under the equity method, the Company's proportionate share of the investee's net income (loss) is included in the unaudited consolidated statements of operations. See Note 14 for additional discussion of the Company's equity method investment.

The accompanying 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, 2015 is derived from audited consolidated financial statements. In the opinion of management, the accompanying unaudited consolidated financial statements reflect all necessary adjustments to present fairly the Company's financial position as of June 30, 2016, results of operations for the three and six months ended June 30, 2016 and 2015 and cash flows for the six months ended June 30, 2016 and 2015.

Certain disclosures have been condensed or omitted from these unaudited consolidated financial statements. Accordingly, these unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in the 2015 Annual Report.

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

The preparation of the accompanying unaudited consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ. The interim results reflected in the unaudited consolidated financial statements are not necessarily indicative of the results that may be expected for other interim periods or for the full year.

Significant estimates include, but are not limited to, (i) estimates of the Company's reserves of oil, NGL and natural gas, (ii) future cash flows from oil and natural gas properties, (iii) depletion, depreciation and amortization, (iv) asset retirement obligations, (v) stock-based compensation, (vi) deferred income taxes, (vii) fair value of assets acquired and liabilities assumed in an acquisition and (viii) fair values of derivatives, deferred premiums and performance unit awards. As fair value is a market-based measurement, it is determined based on the assumptions that would be used by market participants. These estimates and assumptions are based on management's best judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment. Such estimates and assumptions are adjusted when facts and circumstances dictate. Illiquid credit markets and volatile equity and energy markets have combined to increase the uncertainty inherent in such estimates and assumptions. Management believes its estimates and

5

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

assumptions to be reasonable under the circumstances. As future events and their effects cannot be determined with precision, actual values and results could differ from these estimates. Any changes in estimates resulting from future changes in the economic environment will be reflected in the financial statements in future periods.

c.    Reclassifications

Certain amounts in the accompanying unaudited consolidated financial statements have been reclassified to conform to the 2016 presentation. These reclassifications had no impact to previously reported net loss, stockholders' equity or cash flows.

d.    Accounts receivable

The Company sells produced oil, NGL and natural gas and purchased oil to various customers and participates with other parties in the development and operation of oil and natural gas properties. The Company's accounts receivable are generally unsecured. Accounts receivable for joint interest billings are recorded as amounts billed to customers less an allowance for doubtful accounts.

Joint interest operations amounts are considered past due after 30 days. The Company determines joint interest operations accounts receivable allowances based on management's assessment of the creditworthiness of the joint interest owners. Additionally, as the operator of the majority of its wells, the Company has the ability to realize some or all of the receivables through netting of anticipated future production revenues. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses, current receivables aging and existing industry and economic data. The Company reviews its allowance for doubtful accounts quarterly. Past due amounts greater than 90 days and over a specified amount are reviewed individually for collectability. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is remote.

Accounts receivable consisted of the following components for the periods presented:

(in thousands)	June 30, 2016		December 31, 2015
Oil, NGL and natural gas sales	$	42,629	$	25,582
Joint operations, net(1)	18,425		21,375
Sales of purchased oil and other products	15,000		11,775
Matured derivatives	12,223		27,469
Other	266		1,498
Total	$	88,543	$	87,699

______________________________________________________________________________

(1) Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.2 million as of both June 30, 2016 and December 31, 2015.

e.    Derivatives

The Company uses derivatives to reduce exposure to fluctuations in the prices of oil, NGL and natural gas. By removing a significant portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flows from operations due to fluctuations in commodity prices. These transactions are in the form of puts, swaps, collars and, in prior periods, basis swaps.

Derivatives are recorded at fair value and are presented on a net basis on the unaudited consolidated balance sheets as assets or liabilities. The Company nets the fair value of derivatives by counterparty where the right of offset exists. The Company determines the fair value of its derivatives by utilizing pricing models for substantially similar instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. See Note 9 for discussion regarding the fair value of the Company's derivatives. 

The Company's derivatives were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the unaudited consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities. See Notes 8 and 9 for discussion regarding the Company's derivatives.

6

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

f.    Property and equipment

The following table sets forth the Company's property and equipment as of the periods presented:

(in thousands)	June 30, 2016			December 31, 2015
Evaluated oil and natural gas properties	$	5,309,151		$	5,103,635
Less accumulated depletion and impairment	(4,448,482		)	(4,218,942		)
Evaluated oil and natural gas properties, net	860,669			884,693
Unevaluated properties not being depleted	114,507			140,299
Midstream service assets	148,227			147,811
Less accumulated depreciation	(20,175		)	(16,086		)
Midstream service assets, net	128,052			131,725
Depreciable other fixed assets	46,255			46,799
Less accumulated depreciation and amortization	(20,218		)	(18,169		)
Depreciable other fixed assets, net	26,037			28,630
Land	14,914			14,908
Total property and equipment, net	$	1,144,179		$	1,200,255

For the three months ended June 30, 2016 and 2015, depletion expense was $7.06 per barrel of oil equivalent ("BOE") sold and $16.19 per BOE sold, respectively. For the six months ended June 30, 2016 and 2015, depletion expense was $8.01 per BOE sold and $16.13 per BOE sold, respectively.

The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain related employee costs, incurred for the purpose of finding oil, NGL and natural gas are capitalized and depleted on a composite unit of production method based on proved oil, NGL and natural gas reserves. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Costs, including related employee costs, associated with production and general corporate activities are expensed in the period incurred. Sales of oil and natural gas 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 Company excludes the costs directly associated with acquisition and evaluation of unevaluated properties from the depletion calculation until it is determined whether or not proved reserves can be assigned to the properties. The Company capitalizes a portion of its interest costs on its unevaluated properties. Capitalized interest becomes a part of the cost of the unevaluated properties and is subject to depletion when proved reserves can be assigned to the associated properties. All items classified as unevaluated property are assessed on a quarterly basis for possible impairment or reduction in value. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of evaluated reserves and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion.

The full cost ceiling is based principally on the estimated future net revenues from proved oil and natural gas properties discounted at 10%. Per the SEC guidelines, companies are required to use the unweighted arithmetic average first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period before differentials ("Benchmark Prices"). The Benchmark Prices are then adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead ("Realized Prices"). The Realized Prices are utilized to calculate the discounted future net revenues in the full cost ceiling calculation.

7

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

In the event the unamortized cost of evaluated oil and natural gas properties being depleted exceeds the full cost ceiling, as defined by the SEC, the excess is charged to expense in the period such excess occurs. Once incurred, a write-down of oil and natural gas properties is not reversible.

The following table presents the Benchmark Prices, Realized Prices and the corresponding non-cash full cost ceiling impairments recorded as of the periods presented:

	For the quarters ended
	June 30, 2016		March 31, 2016		December 31, 2015		September 30, 2015		June 30, 2015
Benchmark Prices
Oil ($/Bbl)	$	39.63	$	42.77	$	46.79	$	55.73	$	68.17
NGL ($/Bbl)	$	17.08	$	17.51	$	18.75	$	21.87	$	26.73
Natural gas ($/MMBtu)	$	2.17	$	2.31	$	2.47	$	2.89	$	3.22
Realized Prices
Oil ($/Bbl)	$	37.96	$	41.33	$	45.58	$	54.28	$	66.68
NGL ($/Bbl)	$	10.80	$	11.25	$	12.50	$	15.25	$	19.56
Natural gas ($/Mcf)	$	1.64	$	1.75	$	1.89	$	2.30	$	2.62
Non-cash full cost ceiling impairment (in thousands)	$	—	$	161,064	$	975,011	$	906,420	$	488,046

Full cost ceiling impairment expense is included in the "Impairment expense" line item in the unaudited consolidated statements of operations and in the financial information provided for the Company's exploration and production segment presented in Note 16.

g. Long-lived assets and inventory

Impairment losses are recorded on property and equipment used in operations and other long-lived assets when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets' carrying amount. Impairment is measured based on the excess of the carrying amount over the fair value of the asset.

Materials and supplies inventory used in developing oil and natural gas properties and midstream service assets are carried at the lower of cost or market ("LCM") with cost determined using the weighted-average cost method and are included in "Other current assets" and "Other assets, net" on the unaudited consolidated balance sheets. The market price for materials and supplies is determined utilizing a replacement cost approach (Level 2).

Beginning at March 31, 2016, frac pit water inventory used in developing oil and natural gas properties is carried at LCM with cost determined using the weighted-average cost method and is included in "Other current assets" on the unaudited consolidated balance sheets. The market price for frac pit water inventory is determined utilizing a replacement cost approach.

The minimum volume of product in a pipeline system that enables the system to operate is known as line-fill and is generally not available to be withdrawn from the pipeline system until the expiration of the transportation contract. The Company owns oil line-fill in third-party pipelines, which is accounted for at LCM with cost determined using the weighted-average cost method and is included in "Other assets, net" on the unaudited consolidated balance sheets. The LCM adjustment is determined utilizing a quoted market price adjusted for regional price differentials (Level 2).

8

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The following table presents inventory impairments recorded as of the periods presented:

	Three months ended June 30,				Six months ended June 30,
(in thousands)	2016		2015		2016		2015
Inventory impairments:
Materials and supplies(1)	$	963	$	1,553	$	963	$	2,320
Line-fill(2)	—		—		—		111
Total inventory impairments	$	963	$	1,553	$	963	$	2,431

______________________________________________________________________________

(1) Included in "Impairment expense" in the unaudited consolidated statements of operations and in "Impairment expense" for the Company's exploration and production segment presented in Note 16.

(2) Included in "Impairment expense" in the unaudited consolidated statements of operations and in "Impairment expense" for the Company's midstream and marketing segment presented in Note 16.

h.    Debt issuance costs

Debt issuance fees, which are recorded at cost, net of amortization, are amortized over the life of the respective debt agreements utilizing the effective interest and straight-line methods. The Company capitalized $6.8 million of debt issuance costs during the six months ended June 30, 2015 mainly as a result of the issuance of the March 2023 Notes (as defined below). No debt issuance costs were capitalized in the six months ended June 30, 2016. The Company had total debt issuance costs of $20.9 million and $23.9 million, net of accumulated amortization of $19.2 million and $17.0 million, as of June 30, 2016 and December 31, 2015, respectively.

The Company wrote-off approximately $0.8 million of debt issuance costs during the six months ended June 30, 2016 as a result of changes in the borrowing base and aggregate elected commitment of the Senior Secured Credit Facility, which are included in the unaudited consolidated statements of operations in the "Write-off of debt issuance costs" line item. During the six months ended June 30, 2015, the Company wrote-off approximately $6.6 million of debt issuance costs as a result of the early redemption of the January 2019 Notes (as defined below), which are included in the unaudited consolidated statements of operations in the "Loss on early redemption of debt" line item. Unamortized debt issuance costs related to the Company's senior unsecured notes are presented in "Long-term debt, net" on the Company's unaudited consolidated balance sheets. Unamortized debt issuance costs related to the Senior Secured Credit Facility are presented in "Other assets, net" on the Company's unaudited consolidated balance sheets. See Note 5.g for additional discussion of debt issuance costs.

Future amortization expense of debt issuance costs as of the period presented is as follows:

(in thousands)	June 30, 2016
Remaining 2016	$	2,092
2017	4,238
2018	4,068
2019	2,915
2020	3,005
Thereafter	4,585
Total	$	20,903

i.    Other current assets and liabilities

Other current assets consist of the following components for the periods presented:

(in thousands)	June 30, 2016		December 31, 2015
Inventory(1)	$	6,986	$	6,974
Prepaid expenses and other	7,459		7,600
Total other current assets	$	14,445	$	14,574

______________________________________________________________________________

(1) See Note 2.g for discussion of inventory held by the Company.

9

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Other current liabilities consist of the following components for the periods presented:

(in thousands)	June 30, 2016		December 31, 2015
Accrued interest payable	$	24,161	$	24,208
Costs of purchased oil payable	15,629		12,189
Lease operating expense payable	11,570		13,205
Accrued compensation and benefits	8,720		14,342
Capital contribution payable to equity method investee(1)	—		27,583
Other accrued liabilities	12,440		14,695
Total other current liabilities	$	72,520	$	106,222

______________________________________________________________________________

(1) See Notes 14 and 15 for additional discussion regarding our equity method investee.

j.    Asset retirement obligations

Asset retirement obligations associated with the retirement of tangible long-lived assets are recognized as a liability in the period in which they are incurred and become determinable. The associated asset retirement costs are part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related long-lived asset is charged to expense through depletion, or for midstream service asset retirement cost through depreciation, of the associated asset. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and as corresponding accretion expense.

The fair value of additions to the asset retirement obligation liability is measured using valuation techniques consistent with the income approach, which converts future cash flows into a single discounted amount. Significant inputs to the valuation include: (i) estimated plug and abandonment cost per well based on Company experience, (ii) estimated remaining life per well, (iii) estimated removal and/or remediation costs for midstream service assets, (iv) estimated remaining life of midstream service assets, (v) future inflation factors and (vi) the Company's average credit adjusted risk-free rate. Inherent in the fair value calculation of asset retirement obligations are numerous assumptions and judgments including, in addition to those noted above, the ultimate settlement of these amounts, the ultimate timing of such settlement and changes in legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing asset retirement obligation liability, a corresponding adjustment will be made to the asset balance.

The Company is obligated by contractual and regulatory requirements to remove certain pipeline assets and perform other remediation of the sites where such pipeline assets are located upon the retirement of those assets. However, the fair value of the asset retirement obligation cannot currently be reasonably estimated because the settlement dates are indeterminate. The Company will record an asset retirement obligation for pipeline assets in the periods in which settlement dates become reasonably determinable.

The following reconciles the Company's asset retirement obligation liability for the periods presented:

(in thousands)	Six months ended June 30, 2016			Year ended December 31, 2015
Liability at beginning of period	$	46,306		$	32,198
Liabilities added due to acquisitions, drilling, midstream service asset construction and other	253			2,236
Accretion expense	1,704			2,423
Liabilities settled upon plugging and abandonment	(526		)	(146		)
Liabilities removed due to sale of property	—			(2,005		)
Revision of estimates(1)	—			11,600
Liability at end of period	$	47,737		$	46,306

_____________________________________________________________________________

(1) The revision of estimates that occurred during the year ended December 31, 2015 is mainly related to a change in the estimated remaining life per well due to the decline in commodity prices.

10

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

k.    Fair value measurements

The carrying amounts reported in the unaudited consolidated balance sheets for cash and cash equivalents, accounts receivable, accounts payable, undistributed revenue and royalties, accrued capital expenditures and other accrued assets and liabilities approximate their fair values. See Note 5.f for fair value disclosures related to the Company's debt obligations. The Company carries its derivatives at fair value. See Note 9 for details regarding the fair value of the Company's derivatives.

l.    Treasury stock

Laredo's employees may elect to have the Company withhold shares of stock to satisfy their tax withholding obligations that arise upon the lapse of restrictions on their stock awards. Such treasury stock is recorded at cost and retired upon acquisition.

m.    Compensation awards

Stock-based compensation expense, net of amounts capitalized, is included in "General and administrative" in the unaudited consolidated statements of operations over the awards' vesting periods and is based on the awards' grant date fair value. The Company utilizes the closing stock price on the grant date, less an expected forfeiture rate, to determine the fair value of service vesting restricted stock awards and a Black-Scholes pricing model to determine the fair values of service vesting restricted stock option awards. The Company utilizes a Monte Carlo simulation prepared by an independent third party to determine the fair values of the performance share awards and, in prior periods, the performance unit awards. The Company capitalizes a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration and development of its oil and gas properties into the full cost pool. Capitalized stock-based compensation is included as an addition to "Oil and natural gas properties" in the unaudited consolidated balance sheets. See Note 6 for further discussion regarding the restricted stock awards, restricted stock option awards, performance share awards and performance unit awards.

n.    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 June 30, 2016 or December 31, 2015.

o.    Non-cash investing and supplemental cash flow information

The following presents the non-cash investing and supplemental cash flow information for the periods presented:

	Six months ended June 30,
(in thousands)	2016			2015
Non-cash investing information:
Change in accrued capital expenditures	$	(22,012	)	$	(53,209	)
Change in accrued capital contribution to equity method investee(1)	$	(27,583	)	$	27,917
Capitalized asset retirement cost	$	253		$	1,402
Supplemental cash flow information:
Capitalized interest	$	115		$	178

______________________________________________________________________________

(1) See Notes 14 and 15 for additional discussion regarding our equity method investee.

Note 3—Equity offerings

On May 16, 2016, the Company completed the sale of 10,925,000 shares of Laredo's common stock (the "May 2016 Equity Offering") for net proceeds of $119.3 million, after underwriting discounts, commissions and offering expenses. See Note 19.e for discussion regarding the completion of an equity offering subsequent to June 30, 2016.

On March 5, 2015, the Company completed the sale of 69,000,000 shares of Laredo's common stock (the "March 2015 Equity Offering") for net proceeds of $754.2 million, after underwriting discounts, commissions and offering expenses. Entities

11

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

affiliated with Warburg Pincus LLC ("Warburg Pincus") purchased 29,800,000 shares in the March 2015 Equity Offering, following which Warburg Pincus owned 41.0% of Laredo's common stock.

Note 4—Divestiture

a. 2015 Divestiture of non-strategic assets

On September 15, 2015, the Company completed the sale of non-strategic and primarily non-operated properties and associated production totaling 6,060 net acres and 123 producing properties in the Midland Basin to a third-party buyer for a purchase price of $65.5 million. After transaction costs reflecting an economic effective date of July 1, 2015, the net proceeds were $64.8 million, net of working capital adjustments and post-closing adjustments. The purchase price, excluding post-closing adjustments, was allocated to oil and natural gas properties pursuant to the rules governing full cost accounting.

Effective at closing, the operations and cash flows of these properties were eliminated from the ongoing operations of the Company, and the Company has no continuing involvement in the properties. This divestiture does not represent a strategic shift and will not have a major effect on the Company's operations or financial results.

The following table presents revenues and expenses of the oil and natural gas properties sold included in the accompanying unaudited consolidated statements of operations for the periods presented:

(in thousands)	Three months ended June 30, 2015		Six months ended June 30, 2015
Oil, NGL and natural gas sales	$	1,970	$	4,048
Expenses(1)	2,098		4,710

_____________________________________________________________________________

(1) Expenses include (i) lease operating expense, (ii) production and ad valorem tax expense, (iii) accretion expense and (iv) depletion expense.

Note 5—Debt

a.   March 2023 Notes

On March 18, 2015, the Company completed an offering of $350.0 million in aggregate principal amount of 6 1/4% senior unsecured notes due 2023 (the "March 2023 Notes"). The March 2023 Notes will mature on March 15, 2023 and bear an interest rate of 6 1/4% per annum, payable semi-annually, in cash in arrears on March 15 and September 15 of each year, commencing September 15, 2015. The March 2023 Notes are fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain automatic customary releases, including the sale, disposition or transfer of all of the capital stock or of all or substantially all of the assets of a subsidiary guarantor to one or more persons that are not the Company or a restricted subsidiary, exercise of legal defeasance or covenant defeasance options or satisfaction and discharge of the applicable indenture, designation of a subsidiary guarantor as a non-guarantor restricted subsidiary or as an unrestricted subsidiary in accordance with the applicable indenture, release from guarantee under the Senior Secured Credit Facility, or liquidation or dissolution (collectively, the "Releases").

b.    January 2022 Notes

On January 23, 2014, the Company completed an offering of $450.0 million in aggregate principal amount of 5 5/8% senior unsecured notes due 2022 (the "January 2022 Notes"). The January 2022 Notes will mature on January 15, 2022 and bear an interest rate of 5 5/8% per annum, payable semi-annually, in cash in arrears on January 15 and July 15 of each year, commencing July 15, 2014. The January 2022 Notes are fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain Releases.

c.    May 2022 Notes

On April 27, 2012, the Company completed an offering of $500.0 million in aggregate principal amount of 7 3/8% senior unsecured notes due 2022 (the "May 2022 Notes"). The May 2022 Notes will mature on May 1, 2022 and bear an interest rate of 7 3/8% per annum, payable semi-annually, in cash in arrears on May 1 and November 1 of each year, commencing November 1, 2012. The May 2022 Notes are fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain Releases.

12

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

d.    January 2019 Notes

On January 20, 2011, the Company completed an offering of $350.0 million 9 1/2% senior unsecured notes due 2019 (the "January Notes") and on October 19, 2011, the Company completed an offering of an additional $200.0 million 9 1/2% senior unsecured notes due 2019 (the "October Notes" and together with the January Notes, the "January 2019 Notes"). The January 2019 Notes were due to mature on February 15, 2019 and bore an interest rate of 9 1/2% per annum, payable semi-annually, in cash in arrears on February 15 and August 15 of each year. The January 2019 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 April 6, 2015 (the "Redemption Date"), utilizing a portion of the proceeds from the March 2015 Equity Offering and the March 2023 Notes offering, the entire $550.0 million outstanding principal amount of the January 2019 Notes was redeemed at a redemption price of 104.750% of the principal amount of the January 2019 Notes, plus accrued and unpaid interest up to the Redemption Date. The Company recognized a loss on extinguishment of $31.5 million related to the difference between the redemption price and the net carrying amount of the extinguished January 2019 Notes.

e.    Senior Secured Credit Facility

As of June 30, 2016, the Fourth Amended and Restated Credit Agreement (as amended, the "Senior Secured Credit Facility"), which matures on November 4, 2018, had a maximum credit amount of $2.0 billion, a borrowing base and an aggregate elected commitment of $815.0 million with $110.3 million outstanding and was subject to an interest rate of 2.00%. It contains both financial and non-financial covenants, all of which the Company was in compliance with as of June 30, 2016. Laredo is required to pay an annual commitment fee on the unused portion of the financial institutions' commitment of 0.375% to 0.5%, based on the ratio of outstanding revolving credit to the total commitment under the Senior Secured Credit Facility. Additionally, the Senior Secured Credit Facility provides for the issuance of letters of credit, limited to the lesser of total capacity or $20.0 million. No letters of credit were outstanding as of June 30, 2016 or 2015.

See Note 19.a for discussion of additional borrowings and payments on the Senior Secured Credit Facility subsequent to June 30, 2016.

f.    Fair value of debt

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

	June 30, 2016				December 31, 2015
(in thousands)	Long-term debt		Fair value		Long-term debt		Fair value
January 2022 Notes	$	450,000	$	426,564	$	450,000	$	388,301
May 2022 Notes	500,000		501,250		500,000		460,000
March 2023 Notes	350,000		349,965		350,000		301,000
Senior Secured Credit Facility	110,318		110,261		135,000		134,993
Total value of debt	$	1,410,318	$	1,388,040	$	1,435,000	$	1,284,294

The fair values of the debt outstanding on the January 2022 Notes, May 2022 Notes and the March 2023 Notes were determined using the June 30, 2016 and December 31, 2015 quoted market price (Level 1) for each respective instrument. The fair values of the outstanding debt on the Senior Secured Credit Facility as of June 30, 2016 and December 31, 2015 were estimated utilizing pricing models for similar instruments (Level 2). See Note 9 for information about fair value hierarchy levels.

13

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

g.    Debt issuance costs

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

	June 30, 2016							December 31, 2015
(in thousands)	Long-term debt		Debt issuance costs, net			Long-term debt, net		Long-term debt		Debt issuance costs, net			Long-term debt, net
January 2022 Notes	$	450,000	$	(5,451	)	$	444,549	$	450,000	$	(5,939	)	$	444,061
May 2022 Notes	500,000		(6,624		)	493,376		500,000		(7,066		)	492,934
March 2023 Notes	350,000		(5,366		)	344,634		350,000		(5,769		)	344,231
Senior Secured Credit Facility(1)	110,318		—			110,318		135,000		—			135,000
Total	$	1,410,318	$	(17,441	)	$	1,392,877	$	1,435,000	$	(18,774	)	$	1,416,226

______________________________________________________________________________

(1) Debt issuance costs related to our Senior Secured Credit Facility are recorded in "Other assets, net" on the unaudited consolidated balance sheets.

Note 6—Employee compensation

The Company has a Long-Term Incentive Plan (the "LTIP"), which provides for the granting of incentive awards in the form of restricted stock awards, restricted stock option awards, performance share awards, performance unit awards and other awards. In the second quarter of 2016, shareholders approved an increase in the maximum number of shares of the Company's common stock issuable under the LTIP from 10,000,000 shares to 24,350,000 shares (the "Amendment").

The Company recognizes the fair value of stock-based compensation awards expected to vest over the requisite service period as a charge against earnings, net of amounts capitalized. The Company's stock-based compensation awards are accounted for as equity instruments, and in prior periods, its performance unit awards were accounted for as liability awards. Stock-based compensation is included in "General and administrative" in the unaudited consolidated statements of operations. The Company capitalizes a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration and development of oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included as an addition to "Oil and natural gas properties" in the unaudited consolidated balance sheets.

a.    Restricted stock awards

All restricted stock awards are treated as issued and outstanding in the accompanying unaudited consolidated financial statements. Per the award agreement terms, if an employee terminates employment prior to the restriction lapse date for reasons other than death or disability, the awarded shares are forfeited and canceled and are no longer considered issued and outstanding. If the employee's termination of employment is by reason of death or disability, all of the holder's restricted stock will automatically vest. Historically, restricted stock awards granted to officers and employees vest in a variety of vesting schedules including (i) 33%, 33% and 34% per year beginning on the first anniversary date of the grant, (ii) 50% in year two and 50% in year three, (iii) fully on the first anniversary of the grant date and (iv) fully on the third anniversary of the grant date. Restricted stock awards granted to non-employee directors vest fully on the first anniversary of the grant date.

14

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The following table reflects the outstanding restricted stock awards for the six months ended June 30, 2016:

(in thousands, except for weighted-average grant date fair values)	Restricted stock awards		Weighted-average grant date fair value (per award)
Outstanding as of December 31, 2015	2,539		$	15.26
Granted	2,968		$	12.27
Forfeited	(221	)	$	15.16
Vested(1)	(1,124	)	$	16.06
Outstanding as of June 30, 2016	4,162		$	12.92

______________________________________________________________________________

(1) The vesting of certain restricted stock awards could result in federal and state income tax expense or benefit related to the difference between the market price of the common stock at the date of vesting and the date of grant. See Note 7 for additional discussion regarding the tax impact of vested stock awards.

The Company utilizes the closing stock price on the grant date to determine the fair value of service vesting restricted stock awards. As of June 30, 2016, unrecognized stock-based compensation related to the restricted stock awards expected to vest was $44.3 million. Such cost is expected to be recognized over a weighted-average period of 2.26 years.

b.    Restricted stock option awards

Restricted stock option awards granted under the LTIP vest and are exercisable in four equal installments on each of the four anniversaries of the grant date. The following table reflects the stock option award activity for the six months ended June 30, 2016:

(in thousands, except for weighted-average price and contractual term)	Restricted stock option awards		Weighted-average  price (per option)		Weighted-average remaining contractual term (years)
Outstanding as of December 31, 2015	1,778		$	17.86	7.91
Granted	1,016		$	4.18
Exercised	(6	)	$	11.93
Expired or canceled	(35	)	$	22.40
Forfeited	(229	)	$	13.62
Outstanding as of June 30, 2016	2,524		$	12.69	8.06
Vested and exercisable at end of period(1)	916		$	19.49	6.41
Expected to vest at end of period(2)	1,600		$	8.75	9.02

_____________________________________________________________________________

(1) The vested and exercisable options as of June 30, 2016 had no aggregate intrinsic value.

(2) The restricted stock options expected to vest as of June 30, 2016 had $6.1 million aggregate intrinsic value.

The Company utilizes the Black-Scholes option pricing model to determine the fair value of restricted stock option awards and recognizes the associated expense on a straight-line basis over the four-year requisite service period of the awards. Determining the fair value of equity-based awards requires judgment, including estimating the expected term that stock option awards will be outstanding prior to exercise and the associated volatility. As of June 30, 2016, unrecognized stock-based compensation related to restricted stock option awards expected to vest was $13.5 million. Such cost is expected to be recognized over a weighted-average period of 2.55 years.

15

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The assumptions used to estimate the fair value of the 22,324 restricted stock options granted on April 1, 2016 and the 994,022 restricted stock options granted on May 25, 2016 are as follows:

	April 1, 2016			May 25, 2016
Risk-free interest rate(1)	1.44		%	1.58		%
Expected option life(2)	6.25 years			6.25 years
Expected volatility(3)	61.34		%	61.94		%
Fair value per stock option	$	4.44		$	9.75

(1) United States Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, correlating the treasury yield terms to the expected life of the option.

(2) As the Company had limited exercise history at the time of valuation relating to terminations and modifications, expected option life assumptions were developed using the simplified method in accordance with GAAP.

(3) The Company utilized its own historical volatility in order to develop the expected volatility.     

In accordance with the LTIP and stock option agreement, the options granted will become exercisable in accordance with the following schedule based upon the number of full years of the optionee's continuous employment or service with the Company, following the date of grant:

Full years of continuous employment	Incremental percentage of option exercisable		Cumulative percentage of option exercisable
Less than one	—	%	—	%
One	25	%	25	%
Two	25	%	50	%
Three	25	%	75	%
Four	25	%	100	%

No shares of common stock may be purchased unless the optionee has remained in continuous employment with the Company for one year from the grant date. Unless terminated sooner, the option will expire if and to the extent it is not exercised within 10 years from the grant date. The unvested portion of a stock option award shall expire upon termination of employment, and the vested portion of a stock option award shall remain exercisable for (i) one year following termination of employment by reason of the holder's death or disability, but not later than the expiration of the option period, or (ii) 90 days following termination of employment for any reason other than the holder's death or disability, and other than the holder's termination of employment for cause. Both the unvested and the vested but unexercised portion of a stock option award shall expire upon the termination of the option holder's employment or service by the Company for cause.

c.    Performance share awards

The performance share awards granted to management in the second quarter of 2016 (the "2016 Performance Share Awards"), February 27, 2015 (the "2015 Performance Share Awards") and on February 27, 2014 (the "2014 Performance Share Awards") are subject to a combination of market and service vesting criteria. A Monte Carlo simulation prepared by an independent third party was utilized to determine the grant date fair value of these awards. The Company has determined these awards are equity awards and recognizes the associated expense on a straight-line basis over the three-year requisite service period of the awards. These awards will be settled, if at all, in stock at the end of the requisite service period based on the achievement of certain performance criteria.

The 1,742,469 outstanding 2016 Performance Share Awards have a performance period of January 1, 2016 to December 31, 2018, and any shares earned under such awards are expected to be issued in the first quarter of 2019 if the performance criteria are met. The 475,518 outstanding 2015 Performance Share Awards have a performance period of January 1, 2015 to December 31, 2017, and any shares earned under such awards are expected to be issued in the first quarter of 2018 if the performance criteria are met. The 210,126 outstanding 2014 Performance Share Awards have a performance period of January 1, 2014 to December 31, 2016, and any shares earned under such awards are expected to be issued in the first quarter of 2017 if the performance criteria are met.

16

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The following table reflects the performance share award activity for the six months ended June 30, 2016:

(in thousands, except for weighted-average grant date fair values)	Performance share awards		Weighted-average grant date fair value (per award)
Outstanding as of December 31, 2015	874		$	20.06
Granted	1,801		$	17.71
Forfeited	(247	)	$	19.69
Vested	—		$	—
Outstanding as of June 30, 2016	2,428		$	18.36

As of June 30, 2016, unrecognized stock-based compensation related to the performance share awards was $35.3 million. Such cost is expected to be recognized over a weighted-average period of 2.47 years.

The assumptions used to estimate the fair value of the 32,495 performance share awards granted on April 1, 2016 and the 1,768,297 performance share awards granted on May 25, 2016 are as follows:

	April 1, 2016			May 25, 2016
Risk-free rate(1)	0.87		%	1.02		%
Dividend yield	—		%	—		%
Expected volatility(2)	71.54		%	74.73		%
Laredo stock closing price on grant date	$	7.71		$	12.36
Fair value per performance share	$	9.83		$	17.86

______________________________________________________________________________

(1) The risk-free rate was derived using a term-matched zero-coupon yield derived from the Treasury Constant Maturities yield curve on the grant date.

(2) The Company utilized its own historical volatility over a lookback period equal to the length of the remaining performance period from the grant date in order to develop the expected volatility.

d.    Stock-based compensation award expense

The following has been recorded to stock-based compensation expense for the periods presented:

	Three months ended June 30,						Six months ended June 30,
(in thousands)	2016			2015			2016			2015
Restricted stock award compensation	$	4,692		$	4,520		$	8,460		$	7,458
Restricted stock option award compensation	777			1,279			1,401			1,949
Restricted performance share award compensation	1,593			1,378			1,821			2,273
Total stock-based compensation, gross	7,062			7,177			11,682			11,680
Less amounts capitalized in oil and natural gas properties	(989		)	(909		)	(1,771		)	(624		)
Total stock-based compensation, net of amounts capitalized	$	6,073		$	6,268		$	9,911		$	11,056

e.    Performance unit awards

The performance unit awards issued to management on February 15, 2013 (the "2013 Performance Unit Awards") and on February 3, 2012 (the "2012 Performance Unit Awards") were subject to a combination of market and service vesting criteria. These awards were accounted for as liability awards as they were settled in cash at the end of the requisite service period based on the achievement of certain performance criteria.

The 44,481 settled 2013 Performance Unit Awards had a performance period of January 1, 2013 to December 31, 2015 and, as their performance criteria were satisfied, they were paid at $143.75 per unit during the first quarter of 2016. The 27,381 settled 2012 Performance Unit Awards had a performance period of January 1, 2012 to December 31, 2014 and, as their performance criteria were satisfied, they were paid at $100.00 per unit during the first quarter of 2015.

17

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

For the three and six months ended June 30, 2015, compensation expense for the 2013 Performance Unit Awards is included in "General and administrative" in the Company's unaudited consolidated statements of operations, and as of December 31, 2015, the corresponding liability is included in "Other current liabilities" on the unaudited consolidated balance sheets. Due to the quarterly re-measurement of the fair value of the 2013 Performance Unit Awards as of June 30, 2015, compensation expense for the three and six months ended June 30, 2015 was $0.7 million and $1.7 million, respectively.

Note 7—Income taxes

Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating losses and tax credit carry-forwards. Under this method, deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income (loss) in the period that includes the enactment date.

The Company evaluates uncertain tax positions for recognition and measurement in the unaudited consolidated financial statements. To recognize a tax position, the Company determines whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more-likely-than-not threshold is measured to determine the amount of benefit to be recognized in the unaudited consolidated financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. The Company had no unrecognized tax benefits related to uncertain tax positions in the unaudited consolidated financial statements as of June 30, 2016 or December 31, 2015.

The Company is subject to federal and state income taxes and the Texas franchise tax. Income tax benefit for the periods presented consisted of the following:

	Three months ended June 30,				Six months ended June 30,
(in thousands)	2016		2015		2016		2015
Current taxes	$	—	$	—	$	—	$	—
Deferred taxes	—		221,846		—		218,203
Income tax benefit	$	—	$	221,846	$	—	$	218,203

Income tax benefit differed from amounts computed by applying the applicable federal income tax rate of 35% to pre-tax earnings as a result of the following:

	Three months ended June 30,						Six months ended June 30,
(in thousands)	2016			2015			2016			2015
Income tax benefit computed by applying the statutory rate	$	25,001		$	216,608		$	88,131		$	215,498
State income tax and change in valuation allowance	(541		)	5,776			187			5,867
Non-deductible stock-based compensation	—			(15		)	—			(106		)
Stock-based compensation tax deficiency	(190		)	(381		)	(4,012		)	(2,838		)
Increase in deferred tax valuation allowance	(24,323		)	(11		)	(84,218		)	(16		)
Other items	53			(131		)	(88		)	(202		)
Income tax benefit	$	—		$	221,846		$	—		$	218,203

For the three and six months ended June 30, 2016, the effective tax rate was not meaningful due to the valuation allowance recorded. For the three and six months ended June 30, 2015, the effective tax rate was 36% and 35%, respectively. The Company's effective tax rate is affected by changes in valuation allowances, recurring permanent differences and by discrete items that may occur in any given year, but are not consistent from year to year.

A valuation allowance is established to reduce deferred tax assets if it is determined that it is more likely than not that the related tax benefit will not be realized. On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances, if necessary. During the year ended December 31, 2015 and the six months ended June 30, 2016, in evaluating whether it was more likely than not that the Company's net deferred tax assets were realizable through future net income, management considered all available positive and negative evidence, including (i) its earnings history, (ii) its ability to recover net operating loss carry-forwards, (iii) the existence of significant proved oil, NGL and natural gas reserves, (iv) its ability to use tax planning

18

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

strategies, (v) its current price protection utilizing oil and natural gas hedges, (vi) its future revenue and operating cost projections and (vii) the current market prices for oil, NGL and natural gas. Based on all the evidence available, during the year ended December 31, 2015, management determined it was more likely than not that the net deferred tax assets were not realizable, and therefore recorded a valuation allowance of $676.0 million. During the six months ended June 30, 2016, an additional valuation allowance of $83.7 million was recorded.

The impact of significant discrete items is separately recognized in the quarter in which the discrete items occur. The vesting of certain restricted stock awards could result in federal and state income tax expense or benefits related to the difference between the market price of the common stock at the date of vesting and the grant date. The exercise of stock option awards could result in federal and state income tax expense or benefits related to the difference between the fair value of the stock option at the grant date and the intrinsic value of the stock option when exercised. The tax impact resulting from vestings of restricted stock awards and exercise of option awards are discrete items. During the three and six months ended June 30, 2016 and 2015, certain shares related to restricted stock awards vested at times when the Company's stock price was lower than the fair value of those shares at the time of the grant. As a result, the income tax deduction related to such shares is less than the expense previously recognized for book purposes. During the three and six months ended June 30, 2016, certain stock options were exercised. No stock options were exercised during the three and six months ended June 30, 2015. The income tax deduction related to the intrinsic value of the options was less than the expense previously recognized for book purposes. In accordance with GAAP, such shortfalls reduce additional paid-in capital to the extent windfall tax benefits have been previously recognized. However, the Company has not previously recognized any windfall tax benefits. Therefore, such shortfalls are included in income tax expense.

The following table presents the tax impact of these shortfalls for the periods presented:

	Three months ended June 30,						Six months ended June 30,
(in thousands)	2016			2015			2016			2015
Vesting of restricted stock	$	(182	)	$	(388	)	$	(4,057	)	$	(2,889	)
Exercise of restricted stock options	(10		)	—			(10		)	—
Tax expense due to shortfalls	$	(192	)	$	(388	)	$	(4,067	)	$	(2,889	)

Significant components of the Company's net deferred tax asset for the periods presented are as follows:

(in thousands)	June 30, 2016			December 31, 2015
Oil and natural gas properties, midstream service assets and other fixed assets	$	282,612		$	306,997
Net operating loss carry-forward	528,625			479,022
Derivatives	(41,577		)	(98,675		)
Stock-based compensation	9,340			11,597
Equity method investee	(25,612		)	(31,711		)
Accrued bonus	2,544			4,763
Capitalized interest	2,173			2,525
Other	2,901			2,820
Net deferred tax asset before valuation allowance	761,006			677,338
Valuation allowance	(761,006		)	(677,338		)
Net deferred tax asset	$	—		$	—

The Company had federal net operating loss carry-forwards totaling $1.5 billion and state of Oklahoma net operating loss carry-forwards totaling $41.0 million as of June 30, 2016. These carry-forwards begin expiring in 2026. Additionally, these carry-forwards include windfall tax deductions from vestings of certain restricted stock awards and stock option exercises that were not recorded in the Company's income tax provision. The amount of windfall tax benefit recognized in additional paid-in capital is limited to the amount of benefit realized currently in income taxes payable. As of June 30, 2016, the Company had suspended additional paid-in capital credits of $4.5 million related to windfall tax deductions. Upon realization of the net operating loss carry-forwards from such windfall tax deductions, the Company would record a benefit of up to $4.5 million in additional paid-in capital.

The Company's income tax returns for the years 2012 through 2015 remain open and subject to examination by federal tax authorities and/or the tax authorities in Oklahoma and Texas, which are the jurisdictions where the Company has or had operations. Additionally, the statute of limitations for examination of federal net operating loss carry-forwards typically does not begin to run until the year the attribute is utilized in a tax return.

19

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Note 8—Derivatives

a. Derivatives

The Company engages in derivative transactions such as puts, swaps, collars and, in prior periods, basis swaps to hedge price risks due to unfavorable changes in oil and natural gas prices related to its production. As of June 30, 2016, the Company had 25 open derivative contracts with financial institutions that extend from July 2016 to December 2018. None of these contracts were designated as hedges for accounting purposes. The contracts are recorded at fair value on the unaudited consolidated balance sheets and gains and losses are recognized in current period earnings. Gains and losses on derivatives are reported on the unaudited consolidated statements of operations on the "Gain (loss) on derivatives, net" line item.

Each put transaction has an established floor price. The Company pays its counterparty a premium, which can be deferred until settlement, to enter into the put transaction. When the settlement price is below the floor price, the counterparty pays the Company an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the floor price, the put option expires.

Each swap transaction has an established fixed price. When the settlement price is below the fixed price, the counterparty pays the Company an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the fixed price, the Company pays its counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume.

Each collar transaction has an established price floor and ceiling. When the settlement price is below the price floor established by these collars, the Company receives an amount from its counterparty equal to the difference between the settlement price and the price floor multiplied by the hedged contract volume. When the settlement price is above the price ceiling established by these collars, the Company pays its counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the hedged contract volume.

In the prior year, the oil basis swap transactions had an established fixed basis differential. The Company's oil basis swaps' differential was between the West Texas Intermediate-Argus Americas Crude (Midland) ("WTI Midland") index crude oil price and the West Texas Intermediate NYMEX ("WTI NYMEX") index crude oil price. When the WTI NYMEX price less the fixed basis differential was greater than the actual WTI Midland price, the difference multiplied by the hedged contract volume was paid to the Company by the counterparty. When the WTI NYMEX price less the fixed basis differential was less than the actual WTI Midland price, the difference multiplied by the hedged contract volume was paid by the Company to the counterparty.

During the six months ended June 30, 2016, the Company successfully completed a hedge restructuring by early terminating the floors of certain derivative contract collars that resulted in a termination amount of $80 million, which was settled in full by applying the proceeds to prepay the premiums on two new derivatives entered into during the restructuring.

During the six months ended June 30, 2016, the following derivatives were terminated:

	Aggregate volumes	Floor price		Contract period
Oil (volumes in Bbl):
Put portion of the associated collars	2,263,000	$	80.00	January 2017 - December 2017

20

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

During the six months ended June 30, 2016, the following derivatives were entered into:

	Aggregate volumes	Floor price		Ceiling price		Contract period
Oil (volumes in Bbl):
Put(1)	2,263,000	$	60.00	$	—	January 2017 - December 2017
Put(2)	2,098,750	$	60.00	$	—	January 2017 - December 2018
Put(3)	600,000	$	40.00	$	—	May 2016 - December 2016
Swap	1,095,000	$	52.12	$	—	January 2018 - December 2018
Natural gas (volumes in MMBtu):(4)
Put	8,040,000	$	2.50	$	—	January 2017 - December 2017
Put	8,220,000	$	2.50	$	—	January 2018 - December 2018
Collar	5,256,000	$	2.50	$	3.05	January 2017 - December 2017
Collar	4,635,500	$	2.50	$	3.60	January 2018 - December 2018

_____________________________________________________________________________

(1) As part of the Company's hedge restructuring, this put replaced the early terminated put portion of the restructured derivative contract collars. A premium of $40.0 million was paid at contract inception.

(2) As part of the Company's hedge restructuring, a premium of $40.0 million was paid at contract inception.

(3) There are $1.2 million in deferred premiums associated with this contract.

(4) There are $5.1 million in deferred premiums associated with these contracts.

The following represents cash settlements received for derivatives, net for the periods presented:

	Three months ended June 30,				Six months ended June 30,
(in thousands)	2016		2015		2016		2015
Cash settlements received for matured derivatives, net	$	47,382	$	46,596	$	113,319	$	109,737
Cash settlements received for early terminations of derivatives, net(1)	—		—		80,000		—
Cash settlements received for derivatives, net	$	47,382	$	46,596	$	193,319	$	109,737

_____________________________________________________________________________

(1) The settlements amount for the six months ended June 30, 2016 includes $4.0 million in deferred premiums which were settled net with the early terminated contracts from which they derive.

21

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The following table summarizes open positions as of June 30, 2016, and represents, as of such date, derivatives in place through December 2018 on annual production volumes:

	Remaining year 2016		Year 2017		Year 2018
Oil positions:(1)
Puts:
Hedged volume (Bbl)	1,098,000		1,049,375		1,049,375
Weighted-average price ($/Bbl)	$	42.95	$	60.00	$	60.00
Swaps:
Hedged volume (Bbl)	791,200		—		1,095,000
Weighted-average price ($/Bbl)	$	84.82	$	—	$	52.12
Collars:
Hedged volume (Bbl)	1,833,500		2,628,000		—
Weighted-average floor price ($/Bbl)	$	73.98	$	60.00	$	—
Weighted-average ceiling price ($/Bbl)	$	89.62	$	97.22	$	—
Totals:
Total volume hedged with floor price (Bbl)	3,722,700		3,677,375		2,144,375
Weighted-average floor price ($/Bbl)	$	67.13	$	60.00	$	55.98
Total volume hedged with ceiling price (Bbl)	2,624,700		2,628,000		1,095,000
Weighted-average ceiling price ($/Bbl)	$	88.18	$	97.22	$	52.12
Natural gas positions:(2)
Puts:
Hedged volume (MMBtu)	—		8,040,000		8,220,000
Weighted-average price ($/MMBtu)	$	—	$	2.50	$	2.50
Collars:
Hedged volume (MMBtu)	9,384,000		10,731,000		4,635,500
Weighted-average floor price ($/MMBtu)	$	3.00	$	2.76	$	2.50
Weighted-average ceiling price ($/MMBtu)	$	5.60	$	3.53	$	3.60
Totals:
Total volume hedged with floor price (MMBtu)	9,384,000		18,771,000		12,855,500
Weighted-average floor price ($/MMBtu)	$	3.00	$	2.65	$	2.50
Total volume hedged with ceiling price (MMBtu)	9,384,000		10,731,000		4,635,500
Weighted-average ceiling price ($/MMBtu)	$	5.60	$	3.53	$	3.60

_______________________________________________________________________________

(1) Oil derivatives are settled based on the average of the daily settlement prices for the First Nearby Month of the WTI NYMEX Light Sweet Crude Oil Futures Contract for each NYMEX Trading Day during each month.

(2) Natural gas derivatives are settled based on the Inside FERC index price for West Texas Waha for the calculation period.

b. Balance sheet presentation

In accordance with the Company's standard practice, its derivatives are subject to counterparty netting under agreements governing such derivatives. The Company's oil and natural gas derivatives are presented on a net basis as "Derivatives" on the unaudited consolidated balance sheets. See Note 9.a for a summary of the fair value of derivatives on a gross basis.

By using derivatives to hedge exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk. For the Company, market risk is the exposure to changes in the market price of oil and natural gas, which are subject to fluctuations from a variety of factors, including changes in supply and demand. Credit risk is the failure of the

22

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, thereby creating credit risk. The Company's counterparties are participants in the Senior Secured Credit Facility, which is secured by the Company's oil and natural gas reserves; therefore, the Company is not required to post any collateral. The Company does not require collateral from its derivative counterparties. The Company minimizes the credit risk in derivatives by: (i) limiting its exposure to any single counterparty, (ii) entering into derivatives only with counterparties that meet the Company's minimum credit quality standard or have a guarantee from an affiliate that meets the Company's minimum credit quality standard and (iii) monitoring the creditworthiness of the Company's counterparties on an ongoing basis.

Note 9—Fair value measurements

The Company accounts for its oil and natural gas derivatives at fair value. The fair value of derivatives is determined utilizing pricing models for similar instruments. The models use a variety of techniques to arrive at fair value, including quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward curves generated from a compilation of data gathered from third parties.

The Company has categorized its assets and liabilities measured at fair value, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).

Assets and liabilities recorded at fair value on the unaudited consolidated balance sheets are categorized based on inputs to the valuation techniques as follows: 

Level 1—	Assets and liabilities recorded at fair value for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access. Active markets are considered to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2—	Assets and liabilities recorded at fair value for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the assets or liabilities. Substantially all of these inputs are observable in the marketplace throughout the full term of the price risk management instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace.
Level 3—	Assets and liabilities recorded at fair value for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. Unobservable inputs are not corroborated by market data. These inputs reflect management's own assumptions about the assumptions a market participant would use in pricing the asset or liability.

When the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety. The Company conducts a review of fair value hierarchy classifications on an annual basis. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities. Transfers between fair value hierarchy levels are recognized and reported in the period in which the transfer occurred. No transfers between fair value hierarchy levels occurred during the three or six months ended June 30, 2016 or 2015.

23

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

a. Fair value measurement on a recurring basis

The following tables summarize the Company's fair value hierarchy by commodity on a gross basis and the net presentation on the unaudited consolidated balance sheets for derivative assets and liabilities measured at fair value on a recurring basis as of the periods presented:

(in thousands)	Level 1		Level 2			Level 3			Total gross fair value			Amounts offset			Net fair value presented on the unaudited consolidated balance sheets
As of June 30, 2016:
Assets
Current:
Oil derivatives	$	—	$	93,057		$	—		$	93,057		$	(515	)	$	92,542
Natural gas derivatives	—		3,458			—			3,458			(1,165		)	2,293
Oil deferred premiums	—		—			—			—			(5,467		)	(5,467		)
Natural gas deferred premiums	—		—			—			—			(403		)	(403		)
Noncurrent:
Oil derivatives	$	—	$	33,181		$	—		$	33,181		$	—		$	33,181
Natural gas derivatives	—		2,724			—			2,724			(2,724		)	—
Oil deferred premiums	—		—			—			—			(501		)	(501		)
Natural gas deferred premiums	—		—			—			—			—			—
Liabilities
Current:
Oil derivatives	$	—	$	—		$	—		$	—		$	515		$	515
Natural gas derivatives	—		(739		)	—			(739		)	1,165			426
Oil deferred premiums	—		—			(6,784		)	(6,784		)	5,467			(1,317		)
Natural gas deferred premiums	—		—			(1,507		)	(1,507		)	403			(1,104		)
Noncurrent:
Oil derivatives	$	—	$	(1,820	)	$	—		$	(1,820	)	$	—		$	(1,820	)
Natural gas derivatives	—		(774		)	—			(774		)	2,724			1,950
Oil deferred premiums	—		—			(501		)	(501		)	501			—
Natural gas deferred premiums	—		—			(3,870		)	(3,870		)	—			(3,870		)
Net derivative position	$	—	$	129,087		$	(12,662	)	$	116,425		$	—		$	116,425

24

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

(in thousands)	Level 1		Level 2		Level 3			Total gross fair value			Amounts offset			Net fair value presented on the unaudited consolidated balance sheets
As of December 31, 2015:
Assets
Current:
Oil derivatives	$	—	$	194,940	$	—		$	194,940		$	—		$	194,940
Natural gas derivatives	—		13,166		—			13,166			—			13,166
Oil deferred premiums	—		—		—			—			(9,301		)	(9,301		)
Natural gas deferred premiums	—		—		—			—			—			—
Noncurrent:
Oil derivatives	$	—	$	80,302	$	—		$	80,302		$	—		$	80,302
Natural gas derivatives	—		2,459		—			2,459			—			2,459
Oil deferred premiums	—		—		—			—			(4,877		)	(4,877		)
Natural gas deferred premiums	—		—		—			—			(441		)	(441		)
Liabilities
Current:
Oil derivatives	$	—	$	—	$	—		$	—		$	—		$	—
Natural gas derivatives	—		—		—			—			—			—
Oil deferred premiums	—		—		(9,301		)	(9,301		)	9,301			—
Natural gas deferred premiums	—		—		—			—			—			—
Noncurrent:
Oil derivatives	$	—	$	—	$	—		$	—		$	—		$	—
Natural gas derivatives	—		—		—			—			—			—
Oil deferred premiums	—		—		(4,877		)	(4,877		)	4,877			—
Natural gas deferred premiums	—		—		(441		)	(441		)	441			—
Net derivative position	$	—	$	290,867	$	(14,619	)	$	276,248		$	—		$	276,248

These items are included as "Derivatives" on the unaudited consolidated balance sheets. Significant Level 2 assumptions associated with the calculation of discounted cash flows used in the mark-to-market analysis of derivatives include each derivative contract's corresponding commodity index price, appropriate risk-adjusted discount rates and other relevant data.

The Company's deferred premiums associated with its derivative contracts are categorized as Level 3, as the Company utilizes a net present value calculation to determine the valuation. They are considered to be measured on a recurring basis as the derivative contracts they derive from are measured on a recurring basis. As derivative contracts containing deferred premiums are entered into, the Company discounts the associated deferred premium to its net present value at the contract trade date, using the Senior Secured Credit Facility rate at the trade date (historical input rates range from 1.69% to 3.56%), and then records the change in net present value to interest expense over the period from trade until the final settlement date at the end of the contract. After this initial valuation, the net present value of each deferred premium is not adjusted; therefore, significant increases (decreases) in the Senior Secured Credit Facility rate would result in a significantly lower (higher) fair value measurement for each new contract entered into that contained a deferred premium; however, the valuation for the deferred premiums already recorded would remain unaffected. While the Company believes the sources utilized to arrive at the fair value estimates are reliable, different sources or methods could have yielded different fair value estimates; therefore, on a quarterly basis, the valuation is compared to counterparty valuations and a third-party valuation of the deferred premiums for reasonableness.

25

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The following table presents actual cash payments required for deferred premiums for the calendar years presented:

(in thousands)	June 30, 2016
Remaining 2016	$	5,407
2017	5,354
2018	2,100
Total	$	12,861

A summary of the changes in assets classified as Level 3 measurements for the periods presented are as follows:

	Three months ended June 30,						Six months ended June 30,
(in thousands)	2016			2015			2016			2015
Balance of Level 3 at beginning of period	$	(13,054	)	$	(8,882	)	$	(14,619	)	$	(9,285	)
Change in net present value of deferred premiums for derivatives	(61		)	(45		)	(133		)	(88		)
Total purchases and settlements:
Purchases	(1,960		)	(4,409		)	(6,072		)	(5,384		)
Settlements(1)	2,413			1,249			8,162			2,670
Balance of Level 3 at end of period	$	(12,662	)	$	(12,087	)	$	(12,662	)	$	(12,087	)

_____________________________________________________________________________

(1) The amount for the six months ended June 30, 2016 includes $3.9 million which represents the present value of deferred premiums settled in the Company's restructuring upon their early termination.

b. Fair value measurement on a nonrecurring basis

The Company accounts for the impairment of long-lived assets and inventory, if any, at fair value on a nonrecurring basis. For purposes of fair value measurement, it was determined that the impairment of long-lived assets and inventory are classified as Level 3, based on the use of internally developed cash flow models. See Note 2.g for discussion regarding the Company's impairment of (i) materials and supplies for the three months ended June 30, 2016 and the three and six months ended June 30, 2015 and (ii) line-fill for the six months ended June 30, 2015.

The accounting policies for impairment of oil and natural gas properties are discussed in Note 2.f. Significant inputs included in the calculation of discounted cash flows used in the impairment analysis include the Company's estimate of operating and development costs, anticipated production of evaluated reserves and other relevant data. See Note 2.f for discussion regarding the prices used in the calculation of discounted cash flows and the Company's first-quarter 2016 and second-quarter 2015 full cost ceiling impairments.

Note 10—Net loss per share

Basic net loss per share is computed by dividing net loss by the weighted-average number of common shares outstanding for the period. Diluted net loss per share reflects the potential dilution of non-vested restricted stock awards, performance share awards and outstanding restricted stock options. For the three and six months ended June 30, 2016 and 2015, all of these potentially dilutive items were anti-dilutive due to the Company's net loss and, therefore, were excluded from the calculation of diluted net loss per share.

26

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The following is the calculation of basic and diluted weighted-average common shares outstanding and net loss per share for the periods presented:

	Three months ended June 30,						Six months ended June 30,
(in thousands, except for per share data)	2016			2015			2016			2015
Net loss (numerator):
Net loss—basic and diluted	$	(71,432	)	$	(397,034	)	$	(251,803	)	$	(397,506	)
Weighted-average common shares outstanding (denominator):
Basic	217,564			211,078			214,562			186,886
Diluted	217,564			211,078			214,562			186,886
Net loss per share:
Basic	$	(0.33	)	$	(1.88	)	$	(1.17	)	$	(2.13	)
Diluted	$	(0.33	)	$	(1.88	)	$	(1.17	)	$	(2.13	)

Note 11—Credit risk

The Company's oil, NGL and natural gas sales are made to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. The Company's joint operations accounts receivable are from a number of oil and natural gas companies, partnerships, individuals and others who own interests in the oil and natural gas properties operated by the Company. The Company's sales of purchased oil are made to one customer. Management believes that any credit risk imposed by a concentration in the oil and natural gas industry is offset by the creditworthiness of the Company's customer base and industry partners. The Company routinely assesses the recoverability of all material trade and other receivables to determine collectability.

The Company uses derivatives to hedge its exposure to oil and natural gas price volatility. These transactions expose the Company to potential credit risk from its counterparties. In accordance with the Company's standard practice, its derivatives are subject to counterparty netting under agreements governing such derivatives; therefore, the credit risk associated with its derivative counterparties is somewhat mitigated. See Notes 2.e, 8 and 9 for additional information regarding the Company's derivatives.

Note 12—Commitments and contingencies

a.    Litigation

From time to time the Company is involved in legal proceedings and/or may be subject to industry rulings that could bring rise to claims in the ordinary course of business. The Company has concluded that the likelihood is remote that the ultimate resolution of any pending litigation or pending claims will be material or have a material adverse effect on the Company's business, financial position, results of operations or liquidity.

b.    Drilling contract

The Company has committed to several drilling contracts with a third party to facilitate the Company's drilling plans. One of these contracts is for a term of multiple months and contains an early termination clause that requires the Company to potentially pay penalties to the third party should the Company cease drilling efforts. This penalty would negatively impact the Company's financial statements upon early contract termination. The future commitment of $3.0 million as of June 30, 2016 is not recorded in the accompanying unaudited consolidated balance sheets. Management does not currently anticipate the early termination of this contract in 2016.

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 minimal volume penalties. These commitments are normal and customary for the Company's business. Future commitments of $400.2 million as of June 30, 2016 are not recorded in the accompanying unaudited consolidated balance sheets. The Company's production has been equivalent or greater than its delivery commitments during the most recent year, and management expects such production will continue to exceed the Company's future commitments. However, in certain instances, the Company has

27

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

used spot market purchases to meet its commitments in certain locations or due to favorable pricing. Management anticipates continuing this practice in the future. Also, if production is not sufficient to satisfy the Company's delivery commitments, the Company can and may use spot market purchases to fulfill the commitments.

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.    Other commitments

See Notes 2.i, 15.a and 19.b for the amount of and discussion regarding the commitments to the Company's non-consolidated variable interest entity ("VIE").

Note 13—2015 Restructuring

Following the fourth-quarter 2014 drop in oil prices, in an effort to reduce costs and to better position the Company for ongoing efficient growth, on January 20, 2015, the Company executed a company-wide restructuring and reduction in force (the "RIF") that included (i) the relocation of certain employees from the Company's Dallas, Texas area office to the Company's other existing offices in Tulsa, Oklahoma and Midland, Texas; (ii) closing the Company's Dallas, Texas area office; (iii) a workforce reduction of approximately 75 employees and (iv) the release of 24 contract personnel. The RIF was communicated to employees on January 20, 2015 and was generally effective immediately. The Company's compensation committee approved the RIF and the related severance package. The Company incurred $6.0 million in expenses during the six months ended June 30, 2015 related to the RIF. There were no comparative amounts recorded in the six months ended June 30, 2016.

Note 14—Variable interest entity

An entity is referred to as a VIE pursuant to accounting guidance for consolidation if it possesses one of the following criteria: (i) it is thinly capitalized, (ii) the residual equity holders do not control the entity, (iii) the equity holders are shielded from the economic losses, (iv) the equity holders do not participate fully in the entity's residual economics, or (v) the entity was established with non-substantive voting interests. In order to determine if a VIE should be consolidated, an entity must determine if it is the primary beneficiary of the VIE. The primary beneficiary of a VIE is that variable interest-holder possessing a controlling financial interest through: (i) its power to direct the activities of the VIE that most significantly impact the VIE's economic performance and (ii) its obligation to absorb losses or its right to receive benefits from the VIE that could potentially be significant to the VIE. In order to determine whether the Company owns a variable interest in a VIE, a qualitative analysis is performed of the entity's design, organizational structure, primary decision makers and relevant agreements. The Company continually monitors its VIE exposure to determine if any events have occurred that could cause the primary beneficiary to change.

LMS contributed $16.0 million and $42.7 million during the three and six months ended June 30, 2016, respectively, and $14.5 million during the six months ended June 30, 2015, to Medallion Gathering & Processing, LLC, a Texas limited liability company formed on October 12, 2012, and its wholly-owned subsidiaries (together "Medallion"). See Note 19.b for discussion regarding a contribution made to Medallion subsequent to June 30, 2016.

LMS holds 49% of Medallion's ownership units. Medallion was established for the purpose of developing midstream solutions and providing midstream infrastructure to bring oil, NGL and natural gas to market. LMS and the other 51% interest-holder have agreed that the voting rights of Medallion, the profit and loss sharing, and the additional capital contribution requirements shall be equal to the ownership unit percentage held. Additionally, Medallion requires a super-majority vote of 75% for all key operating and business decisions. The Company has determined that Medallion is a VIE. However, LMS is not considered to be the primary beneficiary of the VIE because LMS does not have the power to direct the activities that most significantly affect Medallion's economic performance. As such, Medallion is accounted for under the equity method of accounting with the Company's proportionate share of Medallion's net income reflected in the unaudited consolidated

28

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

statements of operations as "Income from equity method investee" and the carrying amount reflected in the unaudited consolidated balance sheets as "Investment in equity method investee."

During the six months ended June 30, 2016 and 2015, Medallion continued expansion activities on existing portions of its pipeline infrastructure in order to gather and transport additional third-party oil production. During the three months ended June 30, 2015, Medallion began recognizing revenue due to its main pipeline becoming fully operational. See Note 15.a for discussion of items included in the Company's unaudited consolidated financial statements related to Medallion.

During the three months ended June 30, 2015, the Company negotiated a buyout of a minimum volume commitment to Medallion, which was related to natural gas gathering infrastructure Medallion constructed on acreage that the Company does not plan to develop. The portion of the buyout that was related to the Company's minimum volume commitment for future periods was $3.0 million and is included in the unaudited consolidated statements of operations in the line item "Minimum volume commitments" for the period in which the buyout was settled.

Note 15—Related Parties

a.    Medallion

The following table summarizes items included in the unaudited consolidated statements of operations related to Medallion for the periods presented:

	Three months ended June 30,				Six months ended June 30,
(in thousands)	2016		2015		2016		2015
Midstream service revenues	$	—	$	390	$	—	$	487
Minimum volume commitments	—		3,579		—		5,235
Interest and other income	—		—		—		108

The following table summarizes items included in the unaudited consolidated balance sheets related to Medallion as of the dates presented:

(in thousands)	June 30, 2016		December 31, 2015
Accounts receivable, net	$	—	$	1,163
Other assets, net(1)	1,025		1,025
Other current liabilities(2)	102		27,583

______________________________________________________________________________

(1) Amounts included in "Other assets, net" above represent LMS owned line-fill in Medallion's pipeline.

(2) Amounts included in "Other current liabilities" above represent LMS' accrued line-fill purchase in Medallion's pipeline as of June 30, 2016 and capital contribution payable to Medallion as of December 31, 2015.

b.    Targa Resources Corp.

The Company has a gathering and processing arrangement with affiliates of Targa Resources Corp. ("Targa"). One of Laredo's directors was on the board of directors of Targa until May 18, 2015.

The following table summarizes the oil, NGL and natural gas sales and midstream service revenues received from Targa included in the unaudited consolidated statements of operations for the periods presented:

	Three months ended June 30,				Six months ended June 30,
(in thousands)	2016		2015		2016		2015
Oil, NGL and natural gas sales	$	18,112	$	34,012	$	35,917	$	53,643
Midstream service revenues	102		—		237		—

The following table summarizes the amounts included in accounts receivable, net from Targa in the unaudited consolidated balance sheets as of the dates presented:

(in thousands)	June 30, 2016		December 31, 2015
Accounts receivable, net	$	9,337	$	6,097

29

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

c.    Archrock Partners, L.P.

The Company has a compression arrangement with affiliates of Archrock Partners, L.P., formerly Exterran Partners L.P. ("Archrock"). One of Laredo's directors is on the board of directors of Archrock GP LLC, an affiliate of Archrock.

The following table summarizes the lease operating expenses related to Archrock included in the unaudited consolidated statements of operations for the periods presented:

	Three months ended June 30,				Six months ended June 30,
(in thousands)	2016		2015		2016		2015
Lease operating expenses	$	526	$	391	$	1,001	$	776

The following table summarizes the capital expenditures related to Archrock included in the unaudited consolidated statements of cash flows for the periods presented:

	Three months ended June 30,				Six months ended June 30,
(in thousands)	2016		2015		2016		2015
Capital expenditures:
Midstream service assets	$	—	$	18	$	20	$	64

The following table summarizes the amounts included in accounts payable from Archrock in the unaudited consolidated balance sheets as of the dates presented:

(in thousands)	June 30, 2016		December 31, 2015
Accounts payable	$	—	$	13

d.    Helmerich & Payne, Inc.

The Company has had drilling contracts with Helmerich & Payne, Inc. ("H&P"). Laredo's Chairman and Chief Executive Officer is on the board of directors of H&P.

The following table summarizes the capitalized oil and natural gas properties related to H&P included in the unaudited consolidated statements of cash flows for the periods presented:

	Three months ended June 30,				Six months ended June 30,
(in thousands)	2016		2015		2016		2015
Capital expenditures:
Oil and natural gas properties	$	—	$	177	$	—	$	2,434

Note 16—Segments

The Company operates in two business segments: (i) exploration and production and (ii) midstream and marketing. The exploration and production segment is engaged in the acquisition, exploration and development of oil and natural gas properties primarily in the Permian Basin in West Texas. The midstream and marketing segment provides Laredo's exploration and production segment and third parties with products and services that need to be delivered by midstream infrastructure, including oil and natural gas gathering services as well as rig fuel, natural gas lift and water delivery and takeaway in and around Laredo's primary production corridors.

30

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The following table presents selected financial information, for the periods presented, regarding the Company's operating segments on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis:

(in thousands)	Exploration and production			Midstream and marketing			Eliminations			Consolidated company
Three months ended June 30, 2016:
Oil, NGL and natural gas sales	$	102,526		$	—		$	—		$	102,526
Midstream service revenues	—			11,138			(9,506		)	1,632
Sales of purchased oil	—			42,615			—			42,615
Total revenues	102,526			53,753			(9,506		)	146,773
Lease operating expenses, including production tax	29,793			—			(2,586		)	27,207
Midstream service expenses	—			6,572			(5,394		)	1,178
Costs of purchased oil	—			44,012			—			44,012
General and administrative(1)	18,818			1,684			—			20,502
Depletion, depreciation and amortization(2)	31,969			2,208			—			34,177
Impairment expense	963			—			—			963
Other operating costs and expenses(3)	806			54			—			860
Operating income (loss)	$	20,177		$	(777	)	$	(1,526	)	$	17,874
Other financial information:
Income from equity method investee	$	—		$	3,696		$	—		$	3,696
Interest expense(4)	$	(22,050	)	$	(1,462	)	$	—		$	(23,512	)
Capital expenditures	$	(92,089	)	$	(1,488	)	$	—		$	(93,577	)
Gross property and equipment(6)	$	5,484,416		$	366,858		$	(4,604	)	$	5,846,670
Three months ended June 30, 2015:
Oil, NGL and natural gas sales	$	125,679		$	221		$	(346	)	$	125,554
Midstream service revenues	—			4,362			(2,636		)	1,726
Sales of purchased oil	—			55,051			—			55,051
Total revenues	125,679			59,634			(2,982		)	182,331
Lease operating expenses, including production tax	41,423			—			(2,717		)	38,706
Midstream service expenses, including minimum volume commitments	4,399			998			(221		)	5,176
Costs of purchased oil	—			54,417			—			54,417
General and administrative(1)	21,347			1,861			—			23,208
Depletion, depreciation and amortization(2)	69,987			2,125			—			72,112
Impairment expense	489,599			—			—			489,599
Other operating costs and expenses(3)	548			45			—			593
Operating income (loss)	$	(501,624	)	$	188		$	(44	)	$	(501,480	)
Other financial information:
Income from equity method investee	$	—		$	2,914		$	—		$	2,914
Interest expense(4)	$	(22,845	)	$	(1,125	)	$	—		$	(23,970	)
Loss on early redemption of debt(5)	$	(30,056	)	$	(1,481	)	$	—		$	(31,537	)
Capital expenditures	$	(133,259	)	$	(13,841	)	$	—		$	(147,100	)
Gross property and equipment(6)	$	5,170,912		$	257,073		$	(365	)	$	5,427,620

_______________________________________________________________________________

(1) General and administrative expense was allocated based on the number of employees in the respective segment as of June 30, 2016 and 2015. Certain components of general and administrative expense, primarily payroll, deferred compensation and vehicle expenses, were not allocated but were actual expenses for each segment. Land and geology expenses were not allocated to the midstream and marketing segment.

(2) Depletion, depreciation and amortization were actual expenses for each segment with the exception of the allocation of depreciation of other fixed assets, which is based on the number of employees in the respective segment as of June 30, 2016 and 2015.

(3) Other operating costs and expenses consist of accretion of asset retirement obligations. These are actual costs and expenses and were not allocated.

(4) Interest expense was allocated to the exploration and production segment based on gross property and equipment as of June 30, 2016 and 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of June 30, 2016 and 2015.

(5) Loss on early redemption of debt was allocated to the exploration and production segment based on gross property and equipment as of June 30, 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of June 30, 2015.

31

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

(6) Gross property and equipment for the midstream and marketing segment includes investment in equity method investee totaling $213.6 million and $103.2 million as of June 30, 2016 and 2015, respectively. Other fixed assets were allocated based on the number of employees in the respective segment as of June 30, 2016 and 2015.

(in thousands)	Exploration and production			Midstream and marketing			Eliminations			Consolidated company
Six months ended June 30, 2016:
Oil, NGL and natural gas sales	$	175,668		$	—		$	—		$	175,668
Midstream service revenues	—			22,405			(18,972		)	3,433
Sales of purchased oil	—			74,229			—			74,229
Total revenues	175,668			96,634			(18,972		)	253,330
Lease operating expenses, including production tax	59,157			—			(4,997		)	54,160
Midstream service expenses	—			13,081			(11,294		)	1,787
Costs of purchased oil	—			76,958			—			76,958
General and administrative(1)	36,497			3,456			—			39,953
Depletion, depreciation and amortization(2)	71,261			4,394			—			75,655
Impairment expense	162,027			—			—			162,027
Other operating costs and expenses(3)	1,598			106			—			1,704
Operating loss	$	(154,872	)	$	(1,361	)	$	(2,681	)	$	(158,914	)
Other financial information:
Income from equity method investee	$	—		$	5,994		$	—		$	5,994
Interest expense(4)	$	(44,353	)	$	(2,864	)	$	—		$	(47,217	)
Capital expenditures	$	(197,874	)	$	(3,425	)	$	—		$	(201,299	)
Gross property and equipment(6)	$	5,484,416		$	366,858		$	(4,604	)	$	5,846,670
Six months ended June 30, 2015:
Oil, NGL and natural gas sales	$	243,890		$	333		$	(551	)	$	243,672
Midstream service revenues	—			8,045			(5,010		)	3,035
Sales of purchased oil	—			86,318			—			86,318
Total revenues	243,890			94,696			(5,561		)	333,025
Lease operating expenses, including production tax	85,268			—			(5,096		)	80,172
Midstream service expenses, including minimum volume commitments	4,399			4,340			(333		)	8,406
Costs of purchased oil	—			85,617			—			85,617
General and administrative(1)	41,125			3,938			—			45,063
Depletion, depreciation and amortization(2)	140,244			3,810			—			144,054
Impairment expense	490,366			111			—			490,477
Other operating costs and expenses(3)	6,972			242			—			7,214
Operating loss	$	(524,484	)	$	(3,362	)	$	(132	)	$	(527,978	)
Other financial information:
Income from equity method investee	$	—		$	2,481		$	—		$	2,481
Interest expense(4)	$	(53,932	)	$	(2,452	)	$	—		$	(56,384	)
Loss on early redemption of debt(5)	$	(30,056	)	$	(1,481	)	$	—		$	(31,537	)
Capital expenditures	$	(380,872	)	$	(34,314	)	$	—		$	(415,186	)
Gross property and equipment(6)	$	5,170,912		$	257,073		$	(365	)	$	5,427,620

_______________________________________________________________________________

(1) General and administrative expense was allocated based on the number of employees in the respective segment as of June 30, 2016 and 2015. Certain components of general and administrative expense, primarily payroll, deferred compensation and vehicle expenses, were not allocated but were actual expenses for each segment. Land and geology expenses were not allocated to the midstream and marketing segment.

(2) Depletion, depreciation and amortization were actual expenses for each segment with the exception of the allocation of depreciation of other fixed assets, which is based on the number of employees in the respective segment as of June 30, 2016 and 2015.

(3) Other operating costs and expenses consist of accretion of asset retirement obligations for the six months ended June 30, 2016 and 2015 and restructuring expense for the six months ended June 30, 2015. These are actual costs and expenses and were not allocated.

(4) Interest expense was allocated to the exploration and production segment based on gross property and equipment as of June 30, 2016 and 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of June 30, 2016 and 2015.

32

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

(5) Loss on early redemption of debt was allocated to the exploration and production segment based on gross property and equipment as of June 30, 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of June 30, 2015.

(6) Gross property and equipment for the midstream and marketing segment includes investment in equity method investee totaling $213.6 million and $103.2 million as of June 30, 2016 and 2015, respectively. Other fixed assets were allocated based on the number of employees in the respective segment as of June 30, 2016 and 2015.

Note 17—Subsidiary guarantors

The Guarantors have fully and unconditionally guaranteed the January 2022 Notes, the May 2022 Notes, the March 2023 Notes and the Senior Secured Credit Facility (and had guaranteed the January 2019 Notes until the Redemption Date), subject to the Releases. In accordance with practices accepted by the SEC, Laredo has prepared condensed consolidating financial statements to quantify the assets, results of operations and cash flows of such subsidiaries as subsidiary guarantors. The following unaudited condensed consolidating balance sheets as of June 30, 2016 and December 31, 2015, unaudited condensed consolidating statements of operations for the three and six months ended June 30, 2016 and 2015 and unaudited condensed consolidating statements of cash flows for the six months ended June 30, 2016 and 2015 present financial information for Laredo on a stand-alone basis (carrying any investment in subsidiaries under the equity method), financial information for the subsidiary guarantors on a stand-alone basis (carrying any investment in subsidiaries under the equity method), and the consolidation and elimination entries necessary to arrive at the information for the Company on a condensed consolidated basis. Deferred income taxes for LMS and for GCM are recorded on Laredo's statements of financial position, statements of operations and statements of cash flows as they are disregarded entities for income tax purposes. Laredo and the Guarantors are not restricted from making intercompany distributions to each other. During the six months ended June 30, 2016, certain assets were transferred from LMS to Laredo at historical cost. See Note 5.d for a discussion of the early redemption of the January 2019 Notes.

Condensed consolidating balance sheet

June 30, 2016

(Unaudited)

(in thousands)	Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Accounts receivable, net	$	73,429	$	15,114	$	—		$	88,543
Other current assets	120,982		1,737		—			122,719
Total oil and natural gas properties, net	970,445		9,335		(4,604		)	975,176
Total midstream service assets, net	—		128,052		—			128,052
Total other fixed assets, net	40,701		250		—			40,951
Investment in subsidiaries and equity method investee	348,623		213,616		(348,623		)	213,616
Total other long-term assets	37,526		3,568		—			41,094
Total assets	$	1,591,706	$	371,672	$	(353,227	)	$	1,610,151
Accounts payable	$	12,934	$	1,566	$	—		$	14,500
Other current liabilities	120,756		18,556		—			139,312
Long-term debt, net	1,392,877		—		—			1,392,877
Other long-term liabilities	51,373		2,927		—			54,300
Stockholders' equity	13,766		348,623		(353,227		)	9,162
Total liabilities and stockholders' equity	$	1,591,706	$	371,672	$	(353,227	)	$	1,610,151

33

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Condensed consolidating balance sheet

December 31, 2015

(Unaudited)

(in thousands)	Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Accounts receivable, net	$	74,613	$	13,086	$	—		$	87,699
Other current assets	244,477		56		—			244,533
Total oil and natural gas properties, net	1,017,565		9,350		(1,923		)	1,024,992
Total midstream service assets, net	—		131,725		—			131,725
Total other fixed assets, net	43,210		328		—			43,538
Investment in subsidiaries and equity method investee	301,891		192,524		(301,891		)	192,524
Total other long-term assets	84,360		3,916		—			88,276
Total assets	$	1,766,116	$	350,985	$	(303,814	)	$	1,813,287
Accounts payable	$	12,203	$	1,978	$	—		$	14,181
Other current liabilities	158,283		44,351		—			202,634
Long-term debt, net	1,416,226		—		—			1,416,226
Other long-term liabilities	46,034		2,765		—			48,799
Stockholders' equity	133,370		301,891		(303,814		)	131,447
Total liabilities and stockholders' equity	$	1,766,116	$	350,985	$	(303,814	)	$	1,813,287

Condensed consolidating statement of operations

For the three months ended June 30, 2016

(Unaudited)

(in thousands)	Laredo			Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Total revenues	$	102,511		$	53,768	$	(9,506	)	$	146,773
Total costs and expenses	84,137			52,742		(7,980		)	128,899
Operating income	18,374			1,026		(1,526		)	17,874
Interest expense and other, net	(23,501		)	—		—			(23,501		)
Other non-operating income (expense)	(64,779		)	3,692		(4,718		)	(65,805		)
Income (loss) before income tax	(69,906		)	4,718		(6,244		)	(71,432		)
Income tax	—			—		—			—
Net income (loss)	$	(69,906	)	$	4,718	$	(6,244	)	$	(71,432	)

Condensed consolidating statement of operations

For the six months ended June 30, 2016

(Unaudited)

(in thousands)	Laredo			Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Total revenues	$	175,633		$	96,669	$	(18,972	)	$	253,330
Total costs and expenses	334,201			94,334		(16,291		)	412,244
Operating income (loss)	(158,568		)	2,335		(2,681		)	(158,914		)
Interest expense and other, net	(47,107		)	—		—			(47,107		)
Other non-operating income (expense)	(43,447		)	5,983		(8,318		)	(45,782		)
Income (loss) before income tax	(249,122		)	8,318		(10,999		)	(251,803		)
Income tax	—			—		—			—
Net income (loss)	$	(249,122	)	$	8,318	$	(10,999	)	$	(251,803	)

34

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Condensed consolidating statement of operations

For the three months ended June 30, 2015

(Unaudited)

(in thousands)	Laredo			Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Total revenues	$	125,687		$	59,626	$	(2,982	)	$	182,331
Total costs and expenses	629,359			57,390		(2,938		)	683,811
Operating income (loss)	(503,672		)	2,236		(44		)	(501,480		)
Interest expense and other, net	(23,797		)	—		—			(23,797		)
Other non-operating income (expense)	(91,367		)	2,914		(5,150		)	(93,603		)
Income (loss) before income tax	(618,836		)	5,150		(5,194		)	(618,880		)
Deferred income tax benefit	221,846			—		—			221,846
Net income (loss)	$	(396,990	)	$	5,150	$	(5,194	)	$	(397,034	)

Condensed consolidating statement of operations

For the six months ended June 30, 2015

(Unaudited)

(in thousands)	Laredo			Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Total revenues	$	243,833		$	94,753	$	(5,561	)	$	333,025
Total costs and expenses	772,667			93,765		(5,429		)	861,003
Operating income (loss)	(528,834		)	988		(132		)	(527,978		)
Interest expense and other, net	(56,088		)	—		—			(56,088		)
Other non-operating income (expense)	(30,655		)	2,481		(3,469		)	(31,643		)
Income (loss) before income tax	(615,577		)	3,469		(3,601		)	(615,709		)
Deferred income tax benefit	218,203			—		—			218,203
Net income (loss)	$	(397,374	)	$	3,469	$	(3,601	)	$	(397,506	)

Condensed consolidating statement of cash flows

For the six months ended June 30, 2016

(Unaudited)

(in thousands)	Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Net cash flows provided by operating activities	$	139,610		$	7,339		$	(8,318	)	$	138,631
Change in investment between affiliates	(47,069		)	38,751			8,318			—
Capital expenditures and other	(197,540		)	(46,090		)	—			(243,630		)
Net cash flows provided by financing activities	93,154			—			—			93,154
Net decrease in cash and cash equivalents	(11,845		)	—			—			(11,845		)
Cash and cash equivalents at beginning of period	31,153			1			—			31,154
Cash and cash equivalents at end of period	$	19,308		$	1		$	—		$	19,309

35

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Condensed consolidating statement of cash flows

For the six months ended June 30, 2015

(Unaudited)

(in thousands)	Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Net cash flows provided by (used in) operating activities	$	136,092		$	(18,318	)	$	(3,469	)	$	114,305
Change in investment between affiliates	(70,472		)	67,003			3,469			—
Capital expenditures and other	(380,961		)	(48,685		)	—			(429,646		)
Net cash flows provided by financing activities	343,613			—			—			343,613
Net increase in cash and cash equivalents	28,272			—			—			28,272
Cash and cash equivalents at beginning of period	29,320			1			—			29,321
Cash and cash equivalents at end of period	$	57,592		$	1		$	—		$	57,593

Note 18—Recent accounting pronouncements

In March, April and May 2016,the Financial Accounting Standards Board ("FASB"), issued new guidance in Topic 606, Revenue from Contracts with Customers, to address the following potential implementation issues of the new revenue standard: (a) to clarify the implementation guidance on principal versus agent considerations, (b) to clarify the identification of performance obligations and the licensing implementation guidance and (c) to address certain issues in the guidance on assessing collectibility, presentation of sales taxes, noncash consideration, and completed contracts and contract modifications at transition. The effective date and transition requirements for the amendments in these updates are the same as the effective date and transition requirements for the guidance issued in May 2014 and August 2015 to Topic 606. These updates are effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company is currently evaluating the impact this guidance will have on its consolidated financial statements upon adoption of this standard.

In March 2016, the FASB issued new guidance in Topic 323, Investments—Equity Method and Joint Ventures, to eliminate the requirement to retroactively adopt the equity method of accounting when an investment qualifies for use of the equity method as a result of an increase in the level of ownership interest or degree of influence. The amendments in this update are effective for annual periods beginning after December 15, 2016 and interim periods within those annual periods. The amendments in this update should be applied prospectively upon their effective date to increases in the level of ownership interest or degree of influence that result in the adoption of the equity method. Early application of the amendments in this update is permitted. The Company is currently evaluating the impact this guidance will have on its consolidated financial statements upon adoption of this standard.

In March 2016, the FASB issued new guidance in Topic 718, Compensation—Stock Compensation, which seeks to simplifythe income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. The amendments in this update are effective for annual periods beginning after December 15, 2016 and interim periods within those annual periods. Early adoption is permitted for any entity in any interim or annual period. If an entity early adopts the amendments in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the applicable amendments in the same period. The Company is currently evaluating the impact this guidance will have on its consolidated financial statements upon adoption of this standard.

In February 2016, the FASB issued new guidance in Topic 842, Leases. The core principle of the new guidance is that a lessee should recognize the assets and liabilities that arise from leases in the statement of financial position. A lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. When measuring assets and liabilities arising from a lease, a lessee (and a lessor) should include payments to be made in optional periods only if the lessee is reasonably certain to exercise an option to extend the lease or not to exercise an option to terminate the lease. Similarly, optional payments to purchase the underlying asset should be included in the measurement of lease assets and lease liabilities only if the lessee is reasonably certain to exercise that purchase option. Reasonably certain is a high threshold that is consistent with and intended to be applied in the same way as the reasonably assured threshold in the previous leases guidance. In addition, also consistent with the previous leases guidance, a lessee (and a lessor) should exclude most variable lease payments in measuring lease assets and lease liabilities, other than those that depend on an index or a rate or are in substance fixed payments. For leases with a term of

36

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. If a lessee makes this election, it should recognize lease expense for such leases generally on a straight-line basis over the lease term. The recognition, measurement and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from previous GAAP. There continues to be a differentiation between finance leases and operating leases. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. These practical expedients relate to the identification and classification of leases that commenced before the effective date, initial direct costs for leases that commenced before the effective date and the ability to use hindsight in evaluating lessee options to extend or terminate a lease or to purchase the underlying asset. An entity that elects to apply the practical expedients will, in effect, continue to account for leases that commence before the effective date in accordance with previous GAAP unless the lease is modified, except that lessees are required to recognize a right-of-use asset and a lease liability for all operating leases at each reporting date based on the present value of the remaining minimum rental payments that were tracked and disclosed under previous GAAP. The amendments in this update are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application of the amendments in this update is permitted. The Company is currently evaluating the impact this guidance will have on its consolidated financial statements upon adoption of this standard.

In July 2015, the FASB issued new guidance in Topic 330, Inventory, which seeks to simplify the measurement of inventory. The amendments in this update apply to inventory that is measured using all methods excluding last-in, first-out and the retail inventory method. The main substantive provision of this guidance is for an entity to change the subsequent measurement of inventory, within the scope of this guidance, from LCM to the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. The amendments in this update are effective for annual reporting periods beginning after December 15, 2016, including interim periods within those fiscal years and should be applied prospectively with earlier application permitted as of the beginning of an interim or annual reporting period. The Company is currently evaluating the impact this guidance will have on its consolidated financial statements upon adoption of this standard.

In April 2015, the FASB issued new guidance in Subtopic 350-40, Intangibles—Goodwill and Other—Internal-Use Software. The amendments in this update provide guidance to customers about whether a cloud computing arrangement includes a software license. If a cloud computing arrangement includes a software license, then the customer should account for the software license element of the arrangement consistent with the acquisition of other software licenses. If a cloud computing arrangement does not include a software license, the customer should account for the arrangement as a service contract. The guidance will not change GAAP for a customer's accounting for service contracts. In addition, the guidance in this update supersedes paragraph 350-40-25-16. The amendments in this update are effective for annual periods beginning after December 15, 2015, including interim periods within those annual periods and should be applied prospectively to all arrangements entered into or materially modified after the effective date or retrospectively. The Company elected to adopt this guidance in the first quarter of 2016 on a prospective basis, and the adoption did not have an effect on its unaudited consolidated financial statements.

In May 2014, the FASB issued a comprehensive new revenue recognition standard that supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities—Oil and Gas—Revenue Recognition. The core principle of the new guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for transferring those goods or services. The new standard also requires significantly expanded disclosure regarding the qualitative and quantitative information of an entity's nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The standard creates a five-step model that requires companies to exercise judgment when considering the terms of a contract and all relevant facts and circumstances. The standard allows for several transition methods: (a) a full retrospective adoption in which the standard is applied to all of the periods presented, or (b) a modified retrospective adoption in which the standard is applied only to the most current period presented in the financial statements, including additional disclosures of the standard's application impact to individual financial statement line items. This standard is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company is currently evaluating the impact this guidance will have on its consolidated financial statements upon adoption of this standard.

37

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Note 19—Subsequent events

a.   Senior Secured Credit Facility

On July 12, 2016, the Company borrowed $94.7 million on the Senior Secured Credit Facility, after which the outstanding balance under the Senior Secured Credit Facility was $205.0 million. On July 19, 2016, the Company completed the July 2016 Equity Offering (as defined below) and applied the net proceeds to the outstanding balance under the Senior Secured Credit Facility, reducing the balance to $70.0 million.

b.  Medallion contribution

Subsequent to June 30, 2016, the Company approved, and on July 29, 2016 contributed, $16.0 million to fund continued expansion activities on existing portions of Medallion's pipeline infrastructure in order to gather additional third-party production. See Note 14 for additional discussion regarding Medallion and see Note 15.a for discussion of items included in the Company's unaudited consolidated financial statements related to Medallion.

c.    New derivative contracts

Subsequent to June 30, 2016, the Company entered into the following new derivative contracts:

	Aggregate volumes	Price		Contract period
Oil (volumes in Bbl):(1)
Swap	1,003,750	$	51.90	January 2017 - December 2017
Swap	1,003,750	$	51.17	January 2017 - December 2017
NGL (volumes in Bbl):
Swap(2)	444,000	$	11.24	January 2017 - December 2017
Swap(3)	375,000	$	22.26	January 2017 - December 2017

_____________________________________________________________

(1) The associated derivatives will be settled based on the WTI NYMEX index oil price.

(2) The associated derivative will be settled based on the Mont Belvieu Purity Ethane-OPIS price.

(3) The associated derivative will be settled based on the Mont Belvieu Propane (TET)-OPIS price.

d.   Acquisition of proved and unproved oil and natural gas properties

Subsequent to June 30, 2016, the Company entered into an agreement to acquire approximately 9,200 net acres of additional leasehold interests in western Glasscock and Reagan counties within the Company's core development area (which includes production of approximately 300 net BOE/D from existing vertical wells) for an aggregate purchase price of $125.0 million. On July 13 and July 18, 2016, the Company closed portions of this acquisition for approximately $92.7 million and $1.65 million, respectively. The closings on the remaining interests, which are subject to certain preferential purchase rights and consents, are expected to occur as such rights and consents are satisfied or obtained during the third and fourth quarters of 2016.

e.   July equity offering

On July 19, 2016, the Company completed the sale of 13,000,000 shares of Laredo's common stock (the "July 2016 Equity Offering") for net proceeds of approximately $136.3 million, after underwriting discounts, commissions and offering expenses. The Company used the net proceeds from the July 2016 Equity Offering to repay borrowings under its Senior Secured Credit Facility as discussed above in Note 19.a. The Company granted the underwriters a 30-day option to purchase up to an additional 1,950,000 shares of Laredo's common stock on the same terms. On August 4, 2016, the underwriters provided notice of the full exercise of the option. The sale of the additional 1,950,000 shares of Laredo’s common stock pursuant to the option is expected to close on August 9, 2016 and will result in net proceeds to the Company of approximately $20.5 million, after underwriting discounts, commissions and offering expenses.

38

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Note 20—Supplementary information

Costs incurred in oil, NGL and natural gas property acquisition, exploration and development activities

Costs incurred in the acquisition, exploration and development of oil, NGL and natural gas assets are presented below:

	Three months ended June 30,				Six months ended June 30,
(in thousands)	2016		2015		2016		2015
Property acquisition costs:							—
Evaluated	$	—	$	—	$	—	$	—
Unevaluated	—		—		—		—
Exploration	19,769		3,841		27,032		8,354
Development costs(1)	70,806		110,518		152,692		317,190
Total costs incurred	$	90,575	$	114,359	$	179,724	$	325,544

____________________________________________________________________________

(1) The costs incurred for oil, NGL and natural gas development activities include$0.1 million and $0.5 millionin asset retirement obligations for thethree months ended June 30, 2016 and 2015, respectively, and $0.2 million and $1.0 million for the six months ended June 30, 2016 and 2015, respectively.

39

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 should be read in conjunction with the 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 2015 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." 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. All amounts, dollars and percentages presented in this Quarterly Report are rounded and therefore approximate.

Executive overview

We are an independent energy company focused on the acquisition, exploration and development of oil and natural gas properties, and the transportation of oil and natural gas from such properties, primarily in the Permian Basin in West Texas. Since our inception, we have grown primarily through our drilling program coupled with select strategic acquisitions and joint ventures.

Our financial and operating performance for the three months ended June 30, 2016 included the following:

• Oil, NGL and natural gas sales of $102.5 million, compared to $125.6 million for the three months ended June 30, 2015;

• Average daily sales volumes of 47,667 BOE/D, compared to 46,532 BOE/D for the three months ended June 30, 2015;

• Net loss of $71.4 million, compared to net loss of $397.0 million, including a non-cash full cost ceiling impairment of $488.0 million, for the three months ended June 30, 2015; and

• Adjusted EBITDA (a non-GAAP financial measure) of $107.8 million, compared to $117.9 million for the three months ended June 30, 2015. See page 55 for a reconciliation of adjusted EBITDA.

Our financial and operating performance for the six months ended June 30, 2016 included the following:

• Oil, NGL and natural gas sales of $175.7 million, compared to $243.7 million for the six months ended June 30, 2015;

• Average daily sales volumes of 46,935 BOE/D, compared to 47,007 BOE/D for the six months ended June 30, 2015;

• Net loss of $251.8 million, including a non-cash full cost ceiling impairment of $161.1 million, compared to net loss of $397.5 million, including a non-cash full cost ceiling impairment of $488.0 million, for the six months ended June 30, 2015; and

• Adjusted EBITDA (a non-GAAP financial measure) of $203.8 million, compared to $236.5 million for the six months ended June 30, 2015. See page 55 for a reconciliation of adjusted EBITDA.

Reserves, pricing and non-cash full cost ceiling impairment

Our results of operations are heavily influenced by oil, NGL and natural gas prices, which have significantly declined and remain at low levels. Oil, NGL and natural gas price fluctuations are caused by changes in global and regional supply and demand, market uncertainty, economic conditions and a variety of additional factors. Since the inception of our oil and natural gas activities, commodity prices have experienced significant fluctuations, and additional changes in commodity prices may affect the economic viability of, and our ability to fund, our drilling projects, as well as the economic valuation and economic recovery of oil, NGL and natural gas reserves.

Our reserves as of June 30, 2016 and December 31, 2015 are reported in three streams: oil, NGL and natural gas. Net book value of evaluated oil and natural gas properties did not exceed the full cost ceiling amount as of June 30, 2016. As such, we did not record a second-quarter non-cash full cost ceiling impairment. See Note 2.f to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for prices used to value our reserves and additional discussion of our full cost impairments in prior periods.

40

We have entered into a number of derivatives, which have enabled us to offset a portion of the changes in our cash flow caused by price fluctuations on our sales of oil, NGL and natural gas as discussed in "Item 3. Quantitative and Qualitative Disclosures About Market Risk."

Potential future low commodity price impact on our full cost impairment

Oil, NGL and natural gas prices have remained low in the third quarter of 2016. If prices remain at or below the current low levels, subject to numerous factors and inherent limitations, and if all other factors remain constant, we will incur an additional non-cash full cost impairment in the third quarter of 2016, 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 (i) changes in drilling and completion 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-stack horizontal targets, (v) income tax impacts, (vi) potential recognition of additional proved undeveloped reserves, (vii) any potential value added to our proved reserves when testing recoverability from drilling unbooked locations and (viii) the inherent significant volatility in the commodity prices for oil and natural gas exemplified by the large swings in recent months.

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 internal reserve estimation utilized in our quarterly accounting estimates. We use our internal reserve estimates to evaluate, also on a quarterly basis, the reasonableness of our reserve development plans for our reported reserves. Changes in circumstance, including commodity pricing, economic factors and the other uncertainties described above may lead to changes in our reserve development plans.

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

Our hypothetical third-quarter 2016 full cost ceiling calculation has been prepared by substituting (a) $36.24 per barrel for oil, (b) $10.97 per barrel for NGL and (c) $1.64 per MMBtu for natural gas (the "Pro Forma Prices") for the respective Realized Prices as of June 30, 2016. All other inputs and assumptions have been held constant. The Pro Forma 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 on the first day of the month for the 11 months ended August 1, 2016, with the price for August 1, 2016 held constant for the remaining twelfth month of the calculation. Based on these inputs, the implied third-quarter impairment would be $38 million. We believe that substituting the Pro Forma Prices in our June 30, 2016 internal reserve estimates may help provide users with an understanding of the impact of known trends on our September 30, 2016 full cost ceiling test and in preparing our year-end reserve estimates.

Recent developments

Acquisition of proved and unproved oil and natural gas properties

Subsequent to June 30, 2016, we entered into an agreement to acquire approximately 9,200 net acres of additional leasehold interests in western Glasscock and Reagan counties within our core development area (which includes production of approximately 300 net barrels of oil equivalent per day from existing vertical wells) for an aggregate purchase price of $125.0 million. As of July 13 and July18, 2016, we have closed portions of this acquisition for $92.7 million and $1.65 million, respectively. The closings on the remaining interests, which are subject to certain preferential purchase rights and consents, are expected to occur as such rights and consents are satisfied or obtained during the third and fourth quarter of 2016.

July 2016 equity offering

On July 19, 2016, we completed the sale of 13,000,000 shares of Laredo's common stock for net proceeds of $136.3 million, after underwriting discounts, commissions and offering expenses, which were used to repay borrowings under our Senior Secured Credit Facility. We granted the underwriters a 30-day option to purchase up to an additional 1,950,000 shares of Laredo's common stock on the same terms. On August 4, 2016, the underwriters provided notice of the full exercise of the option. The sale of the additional 1,950,000 shares of Laredo’s common stock pursuant to the option is expected to close on August 9, 2016 and will result in net proceeds of $20.5 million, after underwriting discounts, commissions and offering expenses.

41

Core areas of operations

The oil and liquids-rich Permian Basin is characterized by multiple target horizons, extensive production histories, long-lived reserves, high drilling success rates and high initial production rates. As of June 30, 2016, we had assembled 128,504 net acres in the Permian Basin.

Sources of our revenue

Our revenues are primarily derived from the sale of produced oil, NGL and natural gas within the continental United States and the sale of purchased oil, and our revenues do not include the effects of derivatives. For the three months ended June 30, 2016, our revenues were comprised of sales of 54% produced oil, 10% produced NGL, 6% produced natural gas, 29% purchased oil and 1% midstream services. For the six months ended June 30, 2016, our revenues were comprised of sales of 53% produced oil, 9% produced NGL, 7% produced natural gas, 29% purchased oil and 2% midstream services. Our oil, NGL and natural gas revenues may vary significantly from period to period as a result of changes in volumes of production and/or changes in commodity prices. Our sales of purchased oil revenue may vary due to changes in oil prices and market differentials. Our midstream service revenues may vary due to oil throughput fees and the level of services provided to third parties for (i) gathered natural gas, (ii) gas lift fees and (iii) water services.

42

Results of operations consolidated

Three and six months ended June 30, 2016 as compared to the three and six months ended June 30, 2015

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

The following table sets forth information regarding oil, NGL and natural gas sales volumes, revenues and average sales prices per BOE sold, for the periods presented:

	Three months ended June 30,						Six months ended June 30,
	2016			2015			2016			2015
Sales volumes:
Oil (MBbl)	2,012			1,938			4,018			4,110
NGL (MBbl)	1,153			1,095			2,219			2,084
Natural gas (MMcf)	7,038			7,205			13,834			13,885
Oil equivalents (MBOE)(1)(2)	4,338			4,234			8,542			8,508
Average daily sales volumes (BOE/D)(2)	47,667			46,532			46,935			47,007
% Oil	46		%	46		%	47		%	48		%
Oil, NGL and natural gas revenues (in thousands):
Oil	$	79,201		$	98,394		$	134,395		$	189,009
NGL	14,120			14,081			23,172			27,268
Natural gas	9,205			13,079			18,101			27,395
Total revenues	$	102,526		$	125,554		$	175,668		$	243,672
Average sales prices:
Oil, realized ($/Bbl)(3)	$	39.37		$	50.77		$	33.45		$	45.99
NGL, realized ($/Bbl)(3)	$	12.24		$	12.85		$	10.44		$	13.08
Natural gas, realized ($/Mcf)(3)	$	1.31		$	1.82		$	1.31		$	1.97
Average price, realized ($/BOE)(3)	$	23.64		$	29.65		$	20.56		$	28.64
Oil, hedged ($/Bbl)(4)	$	58.86		$	72.39		$	57.85		$	70.87
NGL, hedged ($/Bbl)(4)	$	12.24		$	12.85		$	10.44		$	13.08
Natural gas, hedged ($/Mcf)(4)	$	2.13		$	2.29		$	2.10		$	2.32
Average price, hedged ($/BOE)(4)	$	34.00		$	40.36		$	33.33		$	41.22

________________________________________________________________________

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

(2) The volumes presented are based on actual results and are not calculated using the rounded numbers presented in the table above.

(3) Realized oil, NGL and natural gas prices are the actual prices realized at the wellhead adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. The prices presented are based on actual results and are not calculated using the rounded numbers presented in the table above.

(4) Hedged prices reflect the after-effect of our hedging transactions on our average sales prices. Our calculation of such after-effects includes current period settlements of matured derivatives in accordance with GAAP and an adjustment to reflect premiums incurred previously or upon settlement that are attributable to instruments that settled in the period. The prices presented are based on actual results and are not calculated using the rounded numbers presented in the table above.

43

The following table presents cash settlements received for matured derivatives and premiums incurred previously or upon settlement attributable to instruments that settled during the periods utilized in our calculation of the hedged prices presented above:        

	Three months ended June 30,						Six months ended June 30,
(in thousands)	2016			2015			2016			2015
Cash settlements received for matured derivatives:
Oil	$	41,616		$	42,972		$	102,308		$	104,558
Natural gas	5,766			3,624			11,011			5,179
Total	$	47,382		$	46,596		$	113,319		$	109,737
Premiums paid attributable to contracts that matured during the respective period:
Oil	$	(2,413	)	$	(1,073	)	$	(4,263	)	$	(2,318	)
Natural gas	—			(176		)	—			(352		)
Total	$	(2,413	)	$	(1,249	)	$	(4,263	)	$	(2,670	)

Changes in prices and volumes caused the following changes to our oil, NGL and natural gas revenues between the three months ended June 30, 2016 and 2015:

(in thousands)	Oil			NGL			Natural gas			Total net dollar effect of change
2015 Revenues	$	98,394		$	14,081		$	13,079		$	125,554
Effect of changes in price	(22,921		)	(704		)	(3,570		)	(27,195		)
Effect of changes in volumes	3,728			743			(304		)	4,167
2016 Revenues	$	79,201		$	14,120		$	9,205		$	102,526

Changes in prices and volumes caused the following changes to our oil, NGL and natural gas revenues between the six months ended June 30, 2016 and 2015:

(in thousands)	Oil			NGL			Natural gas			Total net dollar effect of change
2015 Revenues	$	189,009		$	27,268		$	27,395		$	243,672
Effect of changes in price	(50,378		)	(5,855		)	(9,193		)	(65,426		)
Effect of changes in volumes	(4,236		)	1,759			(101		)	(2,578		)
2016 Revenues	$	134,395		$	23,172		$	18,101		$	175,668

Oil revenue. Our oil revenue is a function of oil production volumes sold and average sales prices received for those volumes. The decrease in oil revenue of $19.2 million, or 20%, for the three months ended June 30, 2016 as compared to the three months ended June 30, 2015, is mainly due to a 22% decrease in average oil prices realized, partially offset by a 4% increase in oil production.

The decrease in oil revenue of $54.6 million, or 29%, for the six months ended June 30, 2016 as compared to the six months ended June 30, 2015, is mainly due to a 27% decrease in average oil prices realized and a 2% decrease in oil production.

See "—Results of operations - midstream and marketing" for a discussion of our revenue from sales of purchased oil.

NGL and natural gas revenues. Our NGL and natural gas revenues are a function of NGL and natural gas production volumes sold and average sales prices received for those volumes. NGL revenue of $14.1 million remained mostly unchanged for the three months ended June 30, 2016 as compared to the three months ended June 30, 2015. The decrease in natural gas revenue of $3.9 million, or 30%, for the three months ended June 30, 2016 as compared to the three months ended June 30, 2015, is mainly due to a 28% decrease in average natural gas prices realized.

The decrease in NGL revenue of $4.1 million, or 15%, for the six months ended June 30, 2016 as compared to the six months ended June 30, 2015, is mainly due to a 20% decrease in average NGL prices realized, partially offset by a 6% increase in NGL production. The decrease in natural gas revenue of $9.3 million, or 34%, for the six months ended June 30, 2016 as compared to the six months ended June 30, 2015, is mainly due to a 34% decrease in average natural gas prices realized.

44

Costs and expenses

The following table sets forth information regarding costs and expenses and average costs per BOE sold for the periods presented:

	Three months ended June 30,				Six months ended June 30,
(in thousands except for per BOE sold data)	2016		2015		2016		2015
Costs and expenses:
Lease operating expenses	$	19,225	$	29,206	$	39,743	$	61,586
Production and ad valorem taxes	7,982		9,500		14,417		18,586
Midstream service expenses	1,178		1,597		1,787		3,171
Minimum volume commitments	—		3,579		—		5,235
Costs of purchased oil	44,012		54,417		76,958		85,617
General and administrative(1)	20,502		23,208		39,953		45,063
Restructuring expenses	—		—		—		6,042
Accretion of asset retirement obligations	860		593		1,704		1,172
Depletion, depreciation and amortization	34,177		72,112		75,655		144,054
Impairment expense	963		489,599		162,027		490,477
Total	$	128,899	$	683,811	$	412,244	$	861,003
Average costs per BOE sold:
Lease operating expenses	$	4.43	$	6.90	$	4.65	$	7.24
Production and ad valorem taxes	1.84		2.24		1.69		2.18
Midstream service expenses	0.27		0.38		0.21		0.37
General and administrative(1)	4.73		5.48		4.68		5.30
Depletion, depreciation and amortization	7.88		17.03		8.86		16.93
Total	$	19.15	$	32.03	$	20.09	$	32.02

________________________________________________________________________

(1) General and administrative includes non-cash stock-based compensation, net of amounts capitalized, of$6.1 million and $6.3 million for the three months ended June 30, 2016 and 2015, respectively, and $9.9 million and $11.1 million for the six months ended June 30, 2016 and 2015, respectively.

Lease operating expenses. Lease operating expenses, which include workover expenses, decreased by $10.0 million, or 34%, and $21.8 million, or 35%, for the three and six months ended June 30, 2016, respectively, as compared to the same periods in 2015. Previous investments in field infrastructure, primarily in our four production corridors, including water takeaway and recycling facilities and centralized compression, have lowered expenses and reduced well downtime. We continue to focus on the usage and procurement of products and services related to direct operating expenses.

Production and ad valorem taxes. Production and ad valorem taxes decreased by $1.5 million, or 16%, and $4.2 million, or 22%, for the three and six months ended June 30, 2016, respectively, as compared to the same periods in 2015. This change is mainly due to a decrease in production taxes of $1.1 million and $3.3 million for the three and six months ended June 30, 2016 compared to the same periods in 2015 as a result of the corresponding decrease in oil, NGL and natural gas revenues. Production taxes are based on and fluctuate in proportion to our oil, NGL and natural gas revenue.

Midstream service expenses. See "—Results of operations - midstream and marketing" for a discussion of these expenses.

Minimum volume commitments. See "—Results of operations - midstream and marketing" for a discussion of these expenses.

Costs of purchased oil. See "—Results of operations - midstream and marketing" for a discussion of these expenses.

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General and administrative ("G&A"). The table below shows the changes in the significant components of G&A expense for the periods presented:

(in thousands)	Three months ended June 30, 2016 compared to 2015			Six months ended June 30, 2016 compared to 2015
Changes in G&A:
Performance unit awards	$	(678	)	$	(1,674	)
Salaries, benefits and bonuses, net of amounts capitalized	(1,610		)	(1,424		)
Stock-based compensation, net of amounts capitalized	(195		)	(1,145		)
Professional fees	(714		)	(1,104		)
Other	491			237
Total changes in G&A	$	(2,706	)	$	(5,110	)

G&A expense, excluding stock-based compensation, decreased by $2.5 million, or 15%, and $4.0 million, or 12%, for the three and six months ended June 30, 2016, respectively, compared to the same periods in 2015. One of the main contributors to these decreases was the expense incurred for our 2013 Performance Unit Awards of $1.0 million and $1.7 million during the three and six months ended June 30, 2015, respectively. There was no comparable expense during the three and six months ended June 30, 2016. The performance criteria of these awards were satisfied on December 31, 2015, were paid during the first quarter of 2016 and were accounted for as liability awards.

Other significant contributors to the decreases in G&A expense, excluding stock-based compensation, are (i) reduced personnel expenses and (ii) a decrease in professional fees primarily due to a decrease in nonrecurring projects.

Stock-based compensation, net of amounts capitalized, decreased by $0.2 million, or 3%, and $1.1 million, or 10%, for the three and six months ended June 30, 2016, respectively, compared to the same periods in 2015. As a result of stockholder approval of the Amendment to the LTIP at our 2016 Annual Meeting of Stockholders, on May 25, 2016, the restricted stock awards, restricted stock options and performance awards that were contingent as of March 31, 2016 became granted on May 25, 2016, at which time we began recording expense. For further discussion of our stock-based compensation, see Note 6 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.

The fair values for each of our restricted stock awards issued were calculated based on the value of our stock price on the grant date in accordance with GAAP and are being expensed on a straight-line basis over their associated requisite service periods. The fair values for each of our non-qualified restricted stock options awards were determined using a Black-Scholes valuation model in accordance with GAAP and are being expensed on a straight-line basis over their associated four-year requisite service periods.

Our performance share awards are accounted for as equity awards and are included in stock-based compensation expense. The fair values of the performance share awards issued were based on a projection of the performance of our stock price relative to a peer group, defined in each performance share awards' agreement, utilizing a forward-looking Monte Carlo simulation. The fair values for each of our performance share awards will not be re-measured after their initial grant-date valuation and are being expensed on a straight-line basis over their associated three-year requisite service periods.

See Notes 2.m and 6 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information regarding our stock and performance based compensation.

Restructuring expenses.Restructuring expenses were for the first-quarter 2015 RIF that was undertaken to reduce expenses and better position ourselves for future operations in a low commodity price environment. Restructuring expenses of $6.0 million were incurred during the six months ended June 30, 2015. No comparable expenses were recorded during the six months ended June 30, 2016. See Note 13 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of the RIF.

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

	Three months ended June 30,				Six months ended June 30,
(in thousands except for per BOE sold data)	2016		2015		2016		2015
Depletion of evaluated oil and natural gas properties	$	30,630	$	68,545	$	68,457	$	137,273
Depreciation of midstream service assets	2,097		1,933		4,168		3,580
Depreciation and amortization of other fixed assets	1,450		1,634		3,030		3,201
Total DD&A	$	34,177	$	72,112	$	75,655	$	144,054
DD&A per BOE sold	$	7.88	$	17.03	$	8.86	$	16.93

DD&A decreased by $37.9 million, or 53%, and $68.4 million, or 47%, respectively, for the three and six months ended June 30, 2016, respectively, compared to the same periods in 2015, mainly due to our full cost ceiling impairments totaling $2.4 billion during the year ended December 31, 2015 and $161.1 million during the three months ended March 31, 2016.

Impairment expense. Our net book value of evaluated oil and natural gas properties exceeded the full cost ceiling amount as of March 31, 2016 and as of June 30, 2015, and as a result, non-cash full cost ceiling impairments of $161.1 million and $488.0 million, respectively, were recorded. For further discussion of our non-cash full cost ceiling impairments, see Note 2.f to our unaudited consolidated financial statements included elsewhere in this Quarterly Report. Other less material components of impairment expense for the six months ended June 30, 2016 are $1.0 million for materials and supplies as compared to $2.3 million for materials and supplies and $0.1 million for our line-fill for the six months ended June 30, 2015.

Non-operating income and expense. The following table sets forth the components of non-operating income and expense for the periods presented:

	Three months ended June 30,						Six months ended June 30,
(in thousands)	2016			2015			2016			2015
Non-operating income (expense):
Loss on derivatives, net	$	(68,518	)	$	(63,899	)	$	(50,633	)	$	(744	)
Income from equity method investee	3,696			2,914			5,994			2,481
Interest expense	(23,512		)	(23,970		)	(47,217		)	(56,384		)
Interest and other income	11			173			110			296
Loss on early redemption of debt	—			(31,537		)	—			(31,537		)
Write-off of debt issuance costs	(842		)	—			(842		)	—
Loss on disposal of assets, net	(141		)	(1,081		)	(301		)	(1,843		)
Non-operating expense, net	$	(89,306	)	$	(117,400	)	$	(92,889	)	$	(87,731	)

Loss on derivatives, net. The table below shows the changes in the components of loss on derivatives, net for the periods presented:

(in thousands)	Three months ended June 30, 2016 compared to 2015			Six months ended June 30, 2016 compared to 2015
Changes in loss on derivatives, net:
Fair value of derivatives outstanding	$	(5,405	)	$	(133,471	)
Early terminations of derivatives received	—			80,000
Cash settlements received for matured derivatives	786			3,582
Total changes in loss on derivatives, net	$	(4,619	)	$	(49,889	)

The change in fair value of derivatives outstanding for the three and six months ended June 30, 2016 compared to the same periods in 2015 is the result of the changing relationship between our outstanding contract prices and the associated forward curves used to calculate the fair value of our derivatives in relation to expected market prices. In general, we experience gains during periods of decreasing market prices and losses during periods of increasing market prices. The change in loss on derivatives, net for the six months ended June 30, 2016 compared to 2015 was partially offset by proceeds received in a hedge restructuring in which we early terminated floors of certain derivative contract collars, resulting in a termination amount due to us of $80.0 million. The $80.0 million was settled in full by applying the proceeds to the premiums on two new

47

derivatives entered into as part of the hedge restructuring. Cash settlements received for matured derivatives are based on the cash settlement prices of our matured derivatives compared to the prices specified in the derivative contracts.

See Notes 2.e, 8 and 9 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report and "Item 3. Quantitative and Qualitative Disclosures About Market Risk" for additional information regarding our derivatives.

Income from equity method investee. Income from equity method investee increased by $0.8 million, or 27%, and $3.5 million, or 142%, for the three and six months ended June 30, 2016 compared to the same periods in 2015. During the six months ended June 30, 2016, Medallion, our equity method investee, continued expansion activities on existing portions of its pipeline infrastructure in order to gather additional third-party oil production. Medallion began recognizing revenue during the first quarter of 2015 due to its main pipeline becoming fully operational. The Medallion pipeline system transported 99,000 barrels of oil per day ("BOPD") and 35,000 BOPD for the three months ended June 30, 2016 and 2015, respectively, and 91,000 BOPD and 25,000 BOPD during the six months ended June 30, 2016 and 2015, respectively.

Interest expense. The table below shows the changes in the significant components of interest expense for the periods presented:

(in thousands)	Three months ended June 30, 2016 compared to 2015			Six months ended June 30, 2016 compared to 2015
Changes in interest expense:
January 2019 Notes	$	(867	)	$	(13,865	)
March 2023 Notes	—			4,679
Senior Secured Credit Facility, net of capitalized interest	426			200
Other	(17		)	(181		)
Total change in interest expense	$	(458	)	$	(9,167	)

Interest expense decreased by $0.5 million, or 2%, and $9.2 million, or 16%, for the three and six months ended June 30, 2016, respectively, compared to the same periods in 2015. These decreases are primarily due to the early redemption of the January 2019 Notes on April 6, 2015, which is partially offset by the issuance of the March 2023 Notes. The March 2023 Notes, which began accruing interest on March 18, 2015, have both a lower interest rate and a lower principal amount than the January 2019 Notes.

Loss on disposal of assets, net. Loss on disposal of assets, net decreased by $0.9 million and $1.5 million for the three and six months ended June 30, 2016, respectively, compared to the same periods in 2015 as a result of lower losses related to the sales and write-off of materials and supplies and other fixed assets during 2016 as compared to 2015.

Income tax benefit. The fluctuations in loss before income tax benefit are shown in the table below:

	Three months ended June 30,						Six months ended June 30,
(in thousands)	2016			2015			2016			2015
Loss before income taxes	$	(71,432	)	$	(618,880	)	$	(251,803	)	$	(615,709	)
Income tax benefit	—			221,846			—			218,203
Net loss	$	(71,432	)	$	(397,034	)	$	(251,803	)	$	(397,506	)

During the year ended December 31, 2015, we recorded a valuation allowance against our net deferred tax asset due to uncertainties in the timing of the realization of our deferred tax assets. Because of continued uncertainties in the oil and gas markets, we recorded an additional valuation allowance of $83.7 million during the six months ended June 30, 2016. Due to the recording of these valuation allowances, our effective rates for the current year are not comparable to prior years. For the three and six months ended June 30, 2015, our effective tax rate was 36% and 35%, respectively. For further discussion of our valuation allowance, see Note 7 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.

During the three and six months ended June 30, 2016 and 2015, certain shares related to restricted stock awards vested at times when our stock price was lower than the fair value of those shares on the grant date. As a result, the income tax deduction related to such shares is less than the expense previously recognized for book purposes. During the three and six months ended June 30, 2016, certain stock options were exercised, for which the income tax deduction related to the options' intrinsic value is less than the expense previously recognized for book purposes. There were no stock options exercised during the three and six months ended June 30, 2015. As a result of these differences in book compensation expense and related tax deduction, the tax impact of these shortfalls decreased by $0.2 million and increased by $1.2 million for the three and six months ended June 30, 2016 compared to the same periods in 2015.

48

We utilize a one-pool approach when accounting for the pool of windfall tax benefits in which employees and non-employees are grouped into a single pool. As of June 30, 2016 and 2015, we did not have any eligible windfall tax benefits to offset future shortfalls as no excess tax benefits had been recognized, and therefore the tax impact of these shortfalls is included in income tax expense for these respective periods. We expect income tax provisions for future reporting periods will be impacted by this stock compensation tax deduction shortfall; however, we cannot predict the stock compensation shortfall impact because of dependency upon the future market price of our stock. See Notes 6.a, 6.b and 7 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information.

Results of operations - midstream and marketing

The following table presents selected financial information regarding our midstream and marketing operating segment for the periods presented:

	Three months ended June 30,						Six months ended June 30,
(in thousands)	2016			2015			2016			2015
Natural gas sales	$	—		$	221		$	—		$	333
Midstream service revenues	11,138			4,362			22,405			8,045
Sales of purchased oil	42,615			55,051			74,229			86,318
Total revenues	53,753			59,634			96,634			94,696
Midstream service expenses, including minimum volume commitments	6,572			998			13,081			4,340
Costs of purchased oil	44,012			54,417			76,958			85,617
General and administrative(1)	1,684			1,861			3,456			3,938
Depreciation and amortization(2)	2,208			2,125			4,394			3,810
Other operating costs and expenses(3)	54			45			106			353
Operating income (loss)	$	(777	)	$	188		$	(1,361	)	$	(3,362	)
Other financial information:
Income from equity method investee	$	3,696		$	2,914		$	5,994		$	2,481
Interest expense(4)	$	(1,462	)	$	(1,125	)	$	(2,864	)	$	(2,452	)
Loss on early redemption of debt(5)	$	—		$	(1,481	)	$	—		$	(1,481	)

_______________________________________________________________________________

(1) G&A expense was allocated based on the number of employees in the midstream and marketing segment as of June 30, 2016 and 2015. Certain components of G&A expense, primarily payroll, deferred compensation and vehicle expenses, were not allocated but were actual expenses for each segment. Land and geology expenses were not allocated to the midstream and marketing segment.

(2) Depreciation and amortization were actual expenses for the midstream and marketing segment with the exception of the allocation of depreciation of other fixed assets, which was based on the number of employees in the midstream and marketing segment as of June 30, 2016 and 2015.

(3) Other operating costs and expenses consist of accretion of asset retirement obligations for the three and six months ended June 30, 2016 and 2015 and restructuring expense and impairment for the six months ended June 30, 2015. These are actual costs and expenses and were not allocated.

(4) Interest expense was allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of June 30, 2016 and 2015.

(5) Loss on early redemption of debt was allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of June 30, 2015.

Natural gas sales. These revenues are related to our midstream and marketing segment providing our exploration and production segment with processed natural gas for use in the field. The corresponding cost component of these transactions are included in "Midstream service expenses." See Note 16 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information on the operating segments.

Midstream service revenues. Our midstream service revenues from operations increased by $6.8 million and $14.4 million for the three and six months ended June 30, 2016, respectively, compared to the same periods in 2015. This increase is mainly due to (i) water service revenue that we began recognizing in the third quarter of 2015 and (ii) an increase in volumes of natural gas provided for natural gas lift mainly in our production corridors over the prior periods.

49

Sales of purchased oil. Sales of purchased oil decreased by $12.4 million and $12.1 million for the three and six months ended June 30, 2016, respectively, compared to the same periods in 2015 primarily due to the decrease in oil prices. We purchase oil from third parties in West Texas, transport it on the Bridgetex Pipeline and sell it to a third party in the Houston market.

Midstream service expenses, including minimum volume commitments. Midstream service expenses, including minimum volume commitments in 2015, increased by $5.6 million and $8.7 million for the three and six months ended June 30, 2016 compared to the same periods in 2015. Midstream service expenses primarily represent costs incurred to operate and maintain our (i) oil and natural gas gathering and transportation systems and related facilities, (ii) centralized oil storage tanks, (iii) natural gas lift, rig fuel and centralized compression infrastructure and (iv) water storage, recycling and transportation facilities. The increases are due to continued expansion of the midstream service component of our business.

Costs of purchased oil. Costs of purchased oil decreased by $10.4 million and $8.7 million for the three and six months ended June 30, 2016, respectively, compared to the same periods in 2015 primarily due to the decrease in oil prices. These costs include purchasing oil from third parties and transporting it on the Bridgetex Pipeline.

G&A. Our consolidated G&A expense has decreased for the three and six months ended June 30, 2016 compared to the same periods in 2015. See "—Results of operations consolidated" for a discussion of these costs.

Depreciation and amortization. Depreciation and amortization increased by $0.1 million and $0.6 million for the three and six months ended June 30, 2016 compared to the same periods in 2015 due to the continued expansion of our midstream service infrastructure.

Income from equity method investee. We own 49% of the ownership units of Medallion. As such, weaccount for this investment under the equity method of accounting with our proportionate share of net income reflected in the unaudited consolidated statements of operations as "Income from equity method investee" and the carrying amount reflected in the unaudited consolidated balance sheets as "Investment in equity method investee." During the year ended December 31, 2015, Medallion began recognizing revenue due to its main pipeline becoming fully operational. See Note 14 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information regarding this investment.

Interest expense. Interest expense increased by $0.3 million and $0.4 million for three and six months ended June 30, 2016, respectively, compared to the same periods in 2015. Interest is allocated to the midstream and marketing segment based on its gross property and equipment and life-to-date contributions to its equity method investee. We have expanded the midstream and marketing component of our business and built out our service facilities in the past year in addition to increasing our capital contributions to Medallion compared to prior periods, thereby increasing the interest expense that is allocated to this segment. These increases are slightly offset by significant decreases in our consolidated interest expense. See "—Results of operations consolidated" for a discussion of these decreases.

Liquidity and capital resources

Our primary sources of liquidity have been cash flows from operations, proceeds from equity offerings, proceeds from senior unsecured note offerings, borrowings under our Senior Secured Credit Facility and proceeds from asset dispositions. We believe cash flows from operations (including our hedging program) and availability under our Senior Secured Credit Facility provide sufficient liquidity to manage our cash needs and contractual obligations and to fund expected capital expenditures. Our primary operational uses of capital have been for the acquisition, exploration and development of oil and natural gas properties, LMS' infrastructure development and investments in Medallion.

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 or accelerated 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 debt repurchases, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

We continually seek to maintain a financial profile that provides operational flexibility. However, as evidenced by the decline in our Realized Prices used in our reserves compared to the prior year, the decrease in oil, NGL and natural gas prices may have a negative impact on our ability to raise additional capital and/or maintain our desired levels of liquidity. As of August 2, 2016, we had $745.0 million available for borrowings under our Senior Secured Credit Facility. We believe that our operating cash flow and the aforementioned liquidity sources provide us with the financial resources to implement our planned

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exploration and development activities. We use derivatives to reduce exposure to fluctuations in the prices of oil, NGL and natural gas. As of August 3, 2016, approximately 95% of our anticipated oil production for the last six months of 2016 is hedged at a weighted-average floor price of $67.13 per Bbl and approximately 65% of our anticipated natural gas production for the last six months of 2016 is hedged at a weighted-average floor price of $3.00 per MMBtu.

The following table summarizes our hedge positions that were in place as of August 3, 2016 for the calender years presented:

	Remaining year 2016		Year 2017		Year 2018
Oil positions:(1)(2)
Total volume hedged with floor price (Bbl)	3,722,700		5,684,875		2,144,375
Weighted-average floor price ($/Bbl)	$	67.13	$	57.01	$	55.98
NGL positions:(1)(3)
Total volume hedged with floor price (Bbl)	—		819,000		—
Weighted-average floor price ($/Bbl)	$	—	$	16.28	$	—
Natural gas positions:(4)
Total volume hedged with floor price (MMBtu)	9,384,000		18,771,000		12,855,500
Weighted-average floor price ($/MMBtu)	$	3.00	$	2.65	$	2.50

_______________________________________________________________________________

(1) Includes derivatives entered into subsequent to June 30, 2016.

(2) Oil derivatives are settled based on the WTI NYMEX index oil prices.

(3) NGL derivatives are settled based on the Mont Belvieu-OPIS prices.

(4) Natural gas derivatives are settled based on the Inside FERC index prices for West Texas Waha.

The following table presents a projection of estimated cash received in future periods from oil, NGL and natural gas derivative contracts in place as of June 30, 2016 adjusted for any new hedge transactions entered into between July 1, 2016 and August 3, 2016, utilizing the total volumes hedged with a floor price and the weighted-average floor price for the periods presented:

(in thousands)	Remaining year 2016		Year 2017		Year 2018
Projected oil, NGL and natural gas hedge cash proceeds(1)	$	88,005	$	77,513	$	23,977

_______________________________________________________________________________

(1) For this illustration we utilized the July 26, 2016 (i) WTI index oil spot price of $42.92 per Bbl, (ii) Mont Belvieu Purity Ethane-OPIS spot price of $7.77 (converted to $/Bbl), (iii) Mont Belvieu Propane (TET)-OPIS spot price of $19.24 (converted to $/Bbl) and (iv) Waha natural gas spot price of $2.65 per MMBtu. Prices used were held constant for all periods presented. Additionally, we reduced our projected oil and natural gas hedge cash proceeds by the actual cash payments required for deferred premiums for the calendar years presented.

By removing a significant portion of the price volatility associated with future production, we expect to mitigate, but not eliminate, the potential effects of variability in cash flows from operations due to fluctuations in commodity prices.

On September 15, 2015, we completed the sale of non-strategic and primarily non-operated properties and associated production totaling 6,060 net acres and 123 producing properties in the Midland Basin to a third-party buyer for a purchase price of $65.5 million. After transaction costs reflecting an economic effective date of July 1, 2015, the net proceeds were $64.8 million, net of working capital adjustments and post-closing cost adjustments.

On March 5, 2015, we completed the sale of 69,000,000 shares of Laredo's common stock for net proceeds of $754.2 million, after underwriting discounts, commissions and offering expenses. Entities affiliated with Warburg Pincus purchased 29,800,000 shares in the March 2015 Equity Offering, following which Warburg Pincus owned 41.0% of our common stock.

On March 18, 2015, we completed an offering of $350.0 million in aggregate principal amount of 6 1/4% senior unsecured notes due 2023, which will mature on March 15, 2023 and bear an interest rate of 6 1/4% per annum payable semi-annually in cash in arrears on March 15 and September 15 of each year, commencing September 15, 2015.

On May 16, 2016, we completed the sale of 10,925,000 shares of Laredo's common stock for net proceeds of $119.3 million, after underwriting discounts, commissions and offering expenses.

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As of June 30, 2016, we had $110.3 million outstanding under our Senior Secured Credit Facility and $1.3 billion in senior unsecured notes. We had $704.7 million available for borrowings under our Senior Secured Credit Facility and $19.3 million in cash on hand for total available liquidity of $724.0 million as of June 30, 2016.

Subsequent to June 30, 2016, we completed the sale of 13,000,000 shares of Laredo's common stock for net proceeds of $136.3 million, after underwriting discounts, commissions and offering expenses, which were used to repay borrowings under our Senior Secured Credit Facility. We granted the underwriters a 30-day option to purchase up to an additional 1,950,000 shares of Laredo's common stock on the same terms. On August 4, 2016, the underwriters provided notice of the full exercise of the option. The sale of the additional 1,950,000 shares of Laredo’s common stock pursuant to the option is expected to close on August 9, 2016 and will result in net proceeds of $20.5 million, after underwriting discounts, commissions and offering expenses.

As of August 2, 2016, we had $1.4 billion in debt outstanding, $745.0 million available for borrowings under our Senior Secured Credit Facility and $14.6 million in cash on hand for total available liquidity of $759.6 million. A continued decline in oil and natural gas prices will negatively impact our future borrowing base redeterminations.

Our derivative positions will help us stabilize a portion of our expected cash flows from operations in the event of future declines in the price of oil and natural gas. See "Item 3. Quantitative and Qualitative Disclosures About Market Risk" below.

Cash flows

Our cash flows for the periods presented are as follows:

	Six months ended June 30,
(in thousands)	2016			2015
Net cash provided by operating activities	$	138,631		$	114,305
Net cash used in investing activities	(243,630		)	(429,646		)
Net cash provided by financing activities	93,154			343,613
Net (decrease) increase in cash and cash equivalents	$	(11,845	)	$	28,272

Cash flows provided by operating activities

Net cash provided by operating activities was $138.6 million and $114.3 million for the six months ended June 30, 2016 and 2015, respectively. The increase of $24.3 million during the six months ended June 30, 2016 compared to the same period in 2015 was largely due to the price-related decrease in oil, NGL and natural gas revenue during 2015; however, notable cash flow changes consist of (i) a decrease in impairment expense of $328.5 million, (ii) a decrease in depletion, depreciation and amortization expense of $68.4 million, (iii) an increase in loss on derivatives, net of $49.9 million, (iv) an increase in working capital changes of $47.9 million and (v) a decrease of $31.5 million related to our loss on the early redemption of our January 2019 Notes.

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 and production levels. Regional and worldwide economic activity, weather, infrastructure, capacity to reach markets, costs of operations and other variable factors significantly impact the prices of these commodities. These factors are not within our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see "Item 3. Quantitative and Qualitative Disclosures About Market Risk."

Cash flows used in investing activities

Net cash used in investing activities was $243.6 million and $429.6 million for the six months ended June 30, 2016 and 2015, respectively. The decrease of $186.0 million is mainly attributable to a $177.5 million decrease in capital expenditures for oil and natural gas properties and a $30.7 million decrease in capital expenditures for midstream service assets. These changes partially offset by a $28.2 million increase in investment in our equity method investee.

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Our cash used in investing activities for the periods presented is summarized in the table below:

	Six months ended June 30,
(in thousands)	2016			2015
Capital expenditures:
Oil and natural gas properties	$	(197,042	)	$	(374,508	)
Midstream service assets	(3,425		)	(34,137		)
Other fixed assets	(832		)	(6,541		)
Investment in equity method investee	(42,681		)	(14,495		)
Proceeds from dispositions of capital assets, net of costs	350			35
Net cash used in investing activities	$	(243,630	)	$	(429,646	)

Capital expenditure budget

On May 10, 2016, our board of directors approved an increase to the capital expenditure budget of approximately $75.0 million. Our revised capital expenditure budget is $420.0 million for calendar year 2016, excluding acquisitions and investments in Medallion. We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted. Since we do not direct the expansion activities of Medallion as a 49% owner, we cannot predict future capital commitments.

The amount, timing and allocation of capital expenditures are largely discretionary and within management's control. If oil, NGL and natural gas prices decline below our acceptable levels, or costs increase 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 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, reduction of service costs, contractual obligations, internally generated cash flow and other factors both within and outside our control.

Cash flows provided by financing activities

Net cash provided by financing activities was $93.2 million and $343.6 million for the six months ended June 30, 2016 and 2015, respectively. For the six months ended June 30, 2016, our primary sources of cash provided by financing activities were borrowings on our Senior Secured Credit Facility and proceeds from our May 2016 Equity Offering, partially offset by payments on our Senior Secured Credit Facility. For the six months ended June 30, 2015, our primary sources of cash provided by financing activities were borrowings on our Senior Secured Credit Facility, issuance of our March 2023 Notes and proceeds from our March 2015 Equity Offering, partially offset by our payment in full of our Senior Secured Credit Facility and redemption of our January 2019 Notes.

Our cash provided by financing activities for the periods presented is summarized in the table below:

	Six months ended June 30,
(in thousands)	2016			2015
Borrowings on Senior Secured Credit Facility	$	120,000		$	300,000
Payments on Senior Secured Credit Facility	(144,682		)	(475,000		)
Issuance of March 2023 Notes	—			350,000
Redemption of January 2019 Notes	—			(576,200		)
Proceeds from issuance of common stock, net of offering costs	119,310			754,163
Purchase of treasury stock	(1,541		)	(2,591		)
Proceeds from exercise of employee stock options	67			—
Payments for debt issuance costs	—			(6,759		)
Net cash provided by financing activities	$	93,154		$	343,613

Debt

As of June 30, 2016, we were a party only to our Senior Secured Credit Facility and the indentures governing our senior unsecured notes.

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Senior Secured Credit Facility. As of June 30, 2016, our Senior Secured Credit Facility, which matures November 4, 2018, had a maximum credit amount of $2.0 billion, a borrowing base and an aggregate elected commitment of $815.0 million and $110.3 million outstanding.

The borrowing base under our Senior Secured Credit Facility is subject to a semi-annual redetermination based on the lenders' evaluation of our oil, NGL and natural gas reserves. The lenders have the right to call for an interim redetermination of the borrowing base once between any two redetermination dates and in other specified circumstances. Effective May 2, 2016, in connection with the lenders' regular semi-annual redetermination of the borrowing base, the borrowing base and aggregate elected commitment amounts were each reduced to $815.0 million.

Principal amounts borrowed under the Senior Secured Credit Facility are payable on the final maturity date with such borrowings bearing interest that is payable, at our election, either on the last day of each fiscal quarter at an Adjusted Base Rate or at the end of one-, two-, three-, six- or, to the extent available, 12-month interest periods (and in the case of six- and 12-month interest periods, every three months prior to the end of such interest period) at an Adjusted London Interbank Offered Rate, in each case, plus an applicable margin based on the ratio of the outstanding amount on the Senior Secured Credit Facility to the elected commitment. We are also required to pay an annual commitment fee based on the unused portion of the bank's commitment of 0.375% to 0.5%.

Our Senior Secured Credit Facility is secured by a first-priority lien on certain of our assets, including oil and natural gas properties constituting at least 80% of the present value of our proved reserves owned now or in the future. Our Senior Secured Credit Facility contains both financial and non-financial covenants. We were in compliance with these covenants as of June 30, 2016 and expect to be in compliance with them for the foreseeable future.

Senior unsecured notes. The following table presents principal amounts and applicable interest rates for our outstanding senior unsecured notes as of June 30, 2016:

(in millions, except for interest rates)	Principal		Interest rate
January 2022 Notes	$	450.0	5.625	%
May 2022 Notes	$	500.0	7.375	%
March 2023 Notes	$	350.0	6.250	%

Utilizing proceeds from the March 2023 Notes and the March 2015 Equity Offering, we redeemed the January 2019 Notes in full on April 6, 2015. See Note 5.d to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for information regarding the early redemption of the January 2019 Notes.

Refer to Note 5 of our audited consolidated financial statements included in the 2015 Annual Report and Notes 5 and 19 of our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of the March 2023 Notes, January 2022 Notes, May 2022 Notes, January 2019 Notes and our Senior Secured Credit Facility.

As of August 2, 2016, we had a total of $1.3 billion of senior unsecured notes outstanding and $70.0 million outstanding on the Senior Secured Credit Facility.

Obligations and commitments

As of June 30, 2016, our contractual obligations included our March 2023 Notes, January 2022 Notes, May 2022 Notes, Senior Secured Credit Facility, drilling contract commitments, firm sale and transportation commitments, derivative deferred premiums, asset retirement obligations and office and equipment leases. From December 31, 2015 to June 30, 2016, the material changes in our contractual obligations included (i) a decrease of $42.0 million on our interest obligations for our senior unsecured notes as semi-annual interest payments were made in January, March and May of 2016, (ii) a decrease of $27.6 million in our outstanding capital contribution commitment to our equity method investee due to payments made to Medallion during first-quarter 2016, (iii) a decrease of $25.5 million in our firm sale and transportation commitments, (iv) a decrease of $24.7 million outstanding on our Senior Secured Credit Facility, (v) a decrease of $7.3 million for drilling contract commitments (on contracts other than those on a well-by-well basis) and (vi) a decrease of $6.4 million in our performance unit liability awards as the 2013 Performance Unit Awards were paid in first-quarter 2016.

Refer to Notes 2, 5, 6, 8, 9, 12, 14 and 15 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our contractual obligations.

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Non-GAAP financial measures

The non-GAAP financial measure of Adjusted EBITDA, as defined by us, may not be comparable to similarly titled measures used by other companies. Therefore, this non-GAAP measure 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 flow from operating activities. 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.

Adjusted EBITDA

Adjusted EBITDA is a non-GAAP financial measure that we define as net income or loss plus adjustments for deferred income tax expense or benefit, depletion, depreciation and amortization, bad debt expense, impairment expense, non-cash stock-based compensation, restructuring expenses, gains or losses on derivatives, cash settlements received for matured derivatives, cash settlements on early terminated derivatives, premiums paid for derivatives, interest expense, write-off of debt issuance costs, gains or losses on disposal of assets, loss on early redemption of debt and buyout of minimum volume commitment. Adjusted EBITDA provides no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, working capital movement or tax position. Adjusted EBITDA does not represent funds available for discretionary use because those funds are required for debt service, capital expenditures and working capital, income taxes, franchise taxes and other commitments and obligations. However, our management believes Adjusted EBITDA is useful to an investor in evaluating our operating performance because this measure:

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

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

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

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

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

	Three months ended June 30,						Six months ended June 30,
(in thousands)	2016			2015			2016			2015
Net loss	$	(71,432	)	$	(397,034	)	$	(251,803	)	$	(397,506	)
Plus:
Deferred income tax benefit	—			(221,846		)	—			(218,203		)
Depletion, depreciation and amortization	34,177			72,112			75,655			144,054
Impairment expense	963			489,599			162,027			490,477
Non-cash stock-based compensation, net of amounts capitalized	6,073			6,268			9,911			11,056
Restructuring expenses	—			—			—			6,042
Mark-to-market on derivatives:
Loss on derivatives, net	68,518			63,899			50,633			744
Cash settlements received for matured derivatives, net	47,382			46,596			113,319			109,737
Cash settlements received for early terminations of derivatives, net	—			—			80,000			—
Premiums paid for derivatives	(2,413		)	(1,249		)	(84,263		)	(2,670		)
Interest expense	23,512			23,970			47,217			56,384
Write-off of debt issuance costs	842			—			842			—
Loss on disposal of assets, net	141			1,081			301			1,843
Loss on early redemption of debt	—			31,537			—			31,537
Buyout of minimum volume commitment	—			3,014			—			3,014
Adjusted EBITDA	$	107,763		$	117,947		$	203,839		$	236,509

Critical accounting policies and estimates

The discussion and analysis of our financial condition and results of operations are based upon our unaudited consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our unaudited consolidated financial statements. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our unaudited consolidated financial statements.

In management's opinion, the more significant reporting areas impacted by our judgments and estimates are (i) the choice of accounting method for oil and natural gas activities, (ii) estimation of oil, NGL and natural gas reserve quantities and standardized measure of future net revenues, (iii) impairment of oil and natural gas properties, (iv) revenue recognition, (v) estimation of income taxes, (vi) asset retirement obligations, (vii) valuation of derivatives and deferred premiums, (viii) valuation of stock-based compensation and performance unit compensation and (ix) fair value of assets acquired and liabilities assumed in an acquisition. Management's judgments and estimates in these areas are based on information available from both internal and external sources, including engineers, geologists and historical experience in similar matters. Actual results could differ from these estimates as additional information becomes known.

There have been no material changes in our critical accounting policies and procedures during the six months ended June 30, 2016. For our other critical accounting policies and procedures, please see our disclosure of critical accounting policies in "Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" of the 2015 Annual Report. Additionally, see Note 2 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for a discussion of additional accounting policies and estimates made by management.

Recent accounting pronouncements

See Note 18 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for information regarding recent accounting pronouncements.

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Off-balance sheet arrangements

Currently, we do not have any off-balance sheet arrangements other than operating leases, a drilling contract commitment and firm sale and transportation commitments, which are included in "Obligations and commitments." See Note 12 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information.

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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 instruments were entered into for hedging purposes, rather than for speculative trading.

Commodity price exposure

Due to the inherent volatility in oil, NGL and natural gas prices, we use derivatives, such as puts, swaps, collars and, in prior periods, basis swaps to hedge price risk associated with a significant portion of our anticipated production. By removing a portion of the price volatility associated with future production, we expect to reduce, but not eliminate, the potential effects of variability in cash flows from operations due to fluctuations in commodity prices. We have not elected hedge accounting on these derivatives and, therefore, the gains and losses on open positions are reflected in earnings. At each period-end, we estimate the fair values of our derivatives using an independent third-party valuation and recognize the associated gain or loss in our unaudited consolidated statements of operations.

The fair values of our derivatives are largely determined by estimates of the forward curves of the relevant price indices. As of June 30, 2016, a 10% change in the forward curves associated with our derivatives would have changed our net positions to the following amounts:

(in thousands)	10% Increase		10% Decrease
Derivatives	$	80,867	$	158,740

As of June 30, 2016 and December 31, 2015, the fair values of our open derivative contracts were $116.4 million and $276.2 million, respectively. Refer to Notes 2.e, 8 and 9 of our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional disclosures regarding our derivatives.

Interest rate risk

Our Senior Secured Credit Facility bears interest at a floating rate and, as of June 30, 2016, we had $110.3 million outstanding on our Senior Secured Credit Facility. Our January 2022 Notes, May 2022 Notes and March 2023 Notes bear fixed interest rates and we had $450.0 million, $500.0 million and $350.0 million outstanding, respectively, as of June 30, 2016, as shown in the table below. 

	Expected maturity date
(in millions except for interest rates)	2018			2022			2023			Total
January 2022 Notes - fixed rate	$	—		$	450.0		$	—		$	450.0
Average interest rate	—		%	5.625		%	—		%	5.625		%
May 2022 Notes - fixed rate	$	—		$	500.0		$	—		$	500.0
Average interest rate	—		%	7.375		%	—		%	7.375		%
March 2023 Notes - fixed rate	$	—		$	—		$	350.0		$	350.0
Average interest rate	—		%	—		%	6.250		%	6.250		%
Senior Secured Credit Facility - variable rate	$	110.3		$	—		$	—		$	110.3
Average interest rate	2.000		%	—		%	—		%	2.000		%

Counterparty and customer credit risk

As of June 30, 2016, our principal exposures to credit risk are through receivables of (i) $121.6 million from the fair values of our open derivative contracts, (ii) $42.6 million from the sale of our oil, NGL and natural gas production that we market to energy marketing companies and refineries, (iii) $18.4 million from joint-interest partners, (iv) $15.0 million from sales of purchased oil and other products and (v) $12.2 million from matured derivatives.

We are subject to credit risk due to the concentration of (i) our oil, NGL and natural gas receivables with several significant customers and (ii) our midstream service product sales receivable with one significant customer. On occasion we require our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

We have entered into International Swap Dealers Association Master Agreements ("ISDA Agreements") with each of

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our derivative counterparties, who also are lenders in our Senior Secured Credit Facility. The terms of the ISDA Agreements provide the counterparties and us with rights of offset upon the occurrence of defined acts of default by either a counterparty or us to a derivative, whereby the party not in default may offset all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party.

Refer to Note 11 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional disclosures regarding credit risk.

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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 June 30, 2016. 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 June 30, 2016 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 are not party to any legal proceedings that we currently believe 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 2015 Annual Report. There have been no material changes in our risk factors from those described in the 2015 Annual Report. The risks described in the 2015 Annual Report 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.

Item 2.    Repurchase of Equity Securities

Period	Total number of shares withheld(1)	Average price per share		Total number of shares purchased as part of publicly announced plans	Maximum number of shares that may yet be purchased under the plan
April 1, 2016 - April 30, 2016	5,228	$	9.38	—	—
May 1, 2016 - May 31, 2016	1,360	$	12.07	—	—
June 1, 2016 - June 30, 2016	5,099	$	12.28	—	—
Total	11,687

______________________________________________________________________________

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

Item 3.    Defaults Upon Senior Securities

None.

Item 4.    Mine Safety Disclosures

Not applicable.

Item 5.    Other Information

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

Pursuant to Section 13(r) of the Exchange Act, we may be required to disclose in our annual and quarterly reports to the SEC, whether we or any of our "affiliates" knowingly engaged in certain activities, transactions or dealings relating to Iran or with certain individuals or entities targeted by U.S. economic sanctions. Disclosure is generally required even where the activities, transactions or dealings were conducted in compliance with applicable law. Because the SEC defines the term "affiliate" broadly, it includes any entity under common "control" with us (with the term "control" also being construed broadly by the SEC).

The description of the activities below has been provided to us by Warburg Pincus LLC ("WP"), affiliates of which: (i) beneficially own more than 10% of our outstanding common stock and/or are members of our board of directors and (ii) beneficially own more than 10% of the equity interests of, and have the right to designate members of the board of directors of, Santander Asset Management Investment Holdings Limited ("SAMIH"). SAMIH may therefore be deemed to be under common "control" with us; however, this statement is not meant to be an admission that common control exists.

61

The disclosure below relates solely to activities conducted by SAMIH and its affiliates that may be deemed to be under common "control" with us. The disclosure does not relate to any activities conducted by us or by WP and does not involve our or WP's management. Neither WP nor Laredo has had any involvement in or control over the disclosed activities of SAMIH, and neither WP nor Laredo has independently verified or participated in the preparation of the disclosure. Neither WP nor Laredo is representing to the accuracy or completeness of the disclosure nor do WP or we undertake any obligation to correct or update it.

We understand that one or more SEC-reporting affiliates of SAMIAH intends to disclose in their next annual or quarterly SEC report that:

(a) Santander UK plc ("Santander UK") holds two frozen savings accounts and two frozen current accounts for three customers resident in the United Kingdom ("UK") who are currently designated by the United States ("US") under the Specially Designated Global Terrorist ("SDGT") sanctions program. The accounts held by each customer were blocked after the customer’s designation and have remained blocked and dormant through the first half of 2016. Revenue generated by Santander UK on these accounts in the first half of 2016 was £7.31 whilst net profits in the first half of 2016 were negligible relative to the overall profits of Banco Santander SA.

(b) An Iranian national, resident in the UK, who is currently designated by the US under the Iranian Financial Sanctions Regulations ("IFSR") and the Weapons of Mass Destruction Proliferators Sanctions Regulations, held a mortgage with Santander UK that was issued prior to any such designation. The mortgage account was redeemed and closed on April 13, 2016. No further drawdown has been made (or would be allowed) under this mortgage although Santander UK continued to receive repayment installments prior to redemption. In the first half of 2016, total revenue generated by Santander UK in connection with the mortgage was £434.64 whilst net profits were negligible relative to the overall profits of Banco Santander SA. Santander UK does not intend to enter into any new relationships with this customer, and any disbursements will only be made in accordance with applicable sanctions. The same Iranian national also held two investment accounts with Santander ISA Managers Limited. The funds within both accounts were invested in the same portfolio fund. The accounts remained frozen until the investments were closed on May 12, 2016 and checks issued to customer on May 13, 2016. Total revenue in the first half of 2016 generated by Santander UK in connection with the investment accounts was £7.60 whilst net profits in the first half of 2016 were negligible relative to the overall profits of Banco Santander SA.

(c) A UK national designated by the US under the SDGT sanctions program holds a Santander UK current account. The account remained in arrears through the first half of 2016 (£1,344.01 in debit) and is currently being managed by Santander UK Collections & Recoveries department.

(d) In addition, during the first half of 2016, Santander UK has identified an OFAC match on a power of attorney account. A party listed on the account is currently designated by the US under the SDGT and IFSR sanctions programs. During the first half of 2016, related revenue generated by Santander UK was £129.21 whilst net profits in the first half of 2016 were negligible relative to the overall profits of Banco Santander SA.

62

Item 6.    Exhibits

Exhibit Number	Description
3.1	Amended and Restated Certificate of Incorporation of Laredo Petroleum Holdings, Inc. (incorporated by reference to Exhibit 3.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on December 22, 2011).
3.2	Certificate of Ownership and Merger, dated as of December 30, 2013 (incorporated by reference to Exhibit 3.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on January 6, 2014).
3.3	Second Amended and Restated Bylaws of Laredo Petroleum, Inc. (incorporated by reference to Exhibit 3.3 of Laredo's Annual Report on Form 10-K (File No. 001-35380) filed on February 17, 2016).
4.1	Form of Common Stock Certificate (incorporated by reference to Exhibit 4.1 of Laredo's Registration Statement on Form S-1/A (File No. 333-176439) filed on November 14, 2011).
10.1#	Laredo Petroleum, Inc. Omnibus Equity Incentive Plan, as amended and restated as of March 30, 2016 (incorporated by reference to Exhibit 10.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on May 25, 2016).
10.2#	Form of Restricted Stock Agreement (incorporated by reference to Exhibit 10.2 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on May 25, 2016).
10.3#	Form of Stock Option Agreement (incorporated by reference to Exhibit 10.3 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on May 25, 2016).
10.4#	Form of Performance Share Unit Award Agreement (incorporated by reference to Exhibit 10.4 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on May 25, 2016).
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.INS*	XBRL Instance Document.
101.CAL*	XBRL Schema Document.
101.SCH*	XBRL Calculation Linkbase Document.
101.DEF*	XBRL Definition Linkbase Document.
101.LAB*	XBRL Labels Linkbase Document.
101.PRE*	XBRL Presentation Linkbase Document.

______________________________________________________________________________

*    Filed herewith.

**    Furnished herewith.

#     Management Contract

63

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: August 4, 2016	By:	/s/ Randy A. Foutch
		Randy A. Foutch
		Chairman and Chief Executive Officer
		(principal executive officer)
Date: August 4, 2016	By:	/s/ Richard C. Buterbaugh
		Richard C. Buterbaugh
		Executive Vice President and Chief Financial Officer
		(principal financial officer)
	By:
Date: August 4, 2016	By:	/s/ Michael T. Beyer
		Michael T. Beyer
		Vice President - Controller and Chief Accounting Officer
		(principal accounting officer)

64

EXHIBIT INDEX

Exhibit Number	Description
3.1	Amended and Restated Certificate of Incorporation of Laredo Petroleum Holdings, Inc. (incorporated by reference to Exhibit 3.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on December 22, 2011).
3.2	Certificate of Ownership and Merger, dated as of December 30, 2013 (incorporated by reference to Exhibit 3.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on January 6, 2014).
3.3	Second Amended and Restated Bylaws of Laredo Petroleum, Inc. (incorporated by reference to Exhibit 3.3 of Laredo's Annual Report on Form 10-K (File No. 001-35380) filed on February 17, 2016).
4.1	Form of Common Stock Certificate (incorporated by reference to Exhibit 4.1 of Laredo's Registration Statement on Form S-1/A (File No. 333-176439) filed on November 14, 2011).
10.1#	Laredo Petroleum, Inc. Omnibus Equity Incentive Plan, as amended and restated as of March 30, 2016 (incorporated by reference to Exhibit 10.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on May 25, 2016).
10.2#	Form of Restricted Stock Agreement (incorporated by reference to Exhibit 10.2 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on May 25, 2016).
10.3#	Form of Stock Option Agreement (incorporated by reference to Exhibit 10.3 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on May 25, 2016).
10.4#	Form of Performance Share Unit Award Agreement (incorporated by reference to Exhibit 10.4 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on May 25, 2016).
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.INS*	XBRL Instance Document.
101.CAL*	XBRL Schema Document.
101.SCH*	XBRL Calculation Linkbase Document.
101.DEF*	XBRL Definition Linkbase Document.
101.LAB*	XBRL Labels Linkbase Document.
101.PRE*	XBRL Presentation Linkbase Document.

______________________________________________________________________________

*    Filed herewith.

**    Furnished herewith.

#     Management Contract

65

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, Randy A. Foutch, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Laredo Petroleum, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting(as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 4, 2016
	/s/ Randy A. Foutch
	Randy A. Foutch
	Chairman and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Richard C. Buterbaugh, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Laredo Petroleum, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting(as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 4, 2016
	/s/ Richard C. Buterbaugh
	Richard C. Buterbaugh
	Executive Vice President and Chief Financial Officer

EX-32.1

EXHIBIT 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, Randy A. Foutch, Chairman and Chief Executive Officer of Laredo Petroleum, Inc. (the “Company”), and Richard C. Buterbaugh, Executive Vice President and Chief Financial Officer of the Company, certify that, to their knowledge:

(1) the Quarterly Report on Form 10-Q of the Company for the period ending June 30, 2016, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

August 4, 2016
	/s/ Randy A. Foutch
	Randy A. Foutch
	Chairman and Chief Executive Officer

August 4, 2016
	/s/ Richard C. Buterbaugh
	Richard C. Buterbaugh
	Executive Vice President and Chief Financial Officer

XML

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2016	Aug. 01, 2016
Document and Entity Information [Abstract]
Entity Registrant Name	Laredo Petroleum, Inc.
Entity Central Index Key	0001528129
Document Type	10-Q
Document Period End Date	Jun. 30, 2016
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		240,124,869
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q2

XML

Consolidated balance sheets - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 19,309	$ 31,154
Accounts receivable, net	88,543	87,699
Derivatives	88,965	198,805
Other current assets	14,445	14,574
Total current assets	211,262	332,232
Oil and natural gas properties, full cost method:
Evaluated properties	5,309,151	5,103,635
Unevaluated properties not being depleted	114,507	140,299
Less accumulated depletion and impairment	(4,448,482)	(4,218,942)
Oil and natural gas properties, net	975,176	1,024,992
Midstream service assets, net	128,052	131,725
Other fixed assets, net	40,951	43,538
Property and equipment, net	1,144,179	1,200,255
Derivatives	32,680	77,443
Investment in equity method investee	213,616	192,524
Other assets, net	8,414	10,833
Total assets	1,610,151	1,813,287
Current liabilities:
Accounts payable	14,500	14,181
Undistributed revenue and royalties	25,452	34,540
Accrued capital expenditures	39,860	61,872
Derivatives	1,480	0
Other current liabilities	72,520	106,222
Total current liabilities	153,812	216,815
Long-term debt, net	1,392,877	1,416,226
Derivatives	3,740	0
Asset retirement obligations	46,716	44,759
Other noncurrent liabilities	3,844	4,040
Total liabilities	1,600,989	1,681,840
Commitments and contingencies
Stockholders’ equity:
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued as of June 30, 2016 and December 31, 2015	0	0
Common stock, $0.01 par value, 450,000,000 shares authorized and 227,197,566 and 213,808,003 issued and outstanding as of June 30, 2016 and December 31, 2015, respectively	2,272	2,138
Additional paid-in capital	2,216,036	2,086,652
Accumulated deficit	(2,209,146)	(1,957,343)
Total stockholders’ equity	9,162	131,447
Total liabilities and stockholders’ equity	$ 1,610,151	$ 1,813,287

XML

Consolidated balance sheets (Parenthetical) - $ / shares	Jun. 30, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Preferred stock par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock authorized (in shares)	50,000,000	50,000,000
Preferred stock issued (in shares)	0	0
Common stock par value (in dollars per share)	$ 0.01	$ 0.01
Common stock authorized (in shares)	450,000,000	450,000,000
Common stock issued (in shares)	227,197,566	213,808,003
Common stock outstanding (in shares)	227,197,566	213,808,003

XML

Consolidated statements of operations - USD ($) shares in Thousands, $ in Thousands	3 Months Ended				6 Months Ended
	Jun. 30, 2016		Jun. 30, 2015		Jun. 30, 2016		Jun. 30, 2015
Revenues:
Oil, NGL and natural gas sales	$ 102,526		$ 125,554		$ 175,668		$ 243,672
Midstream service revenues	1,632		1,726		3,433		3,035
Sales of purchased oil	42,615		55,051		74,229		86,318
Total revenues	146,773		182,331		253,330		333,025
Costs and expenses:
Lease operating expenses	19,225		29,206		39,743		61,586
Production and ad valorem taxes	7,982		9,500		14,417		18,586
Midstream service expenses	1,178		1,597		1,787		3,171
Minimum volume commitments	0		3,579		0		5,235
Costs of purchased oil	44,012		54,417		76,958		85,617
General and administrative	20,502	[1]	23,208	[1]	39,953	[2]	45,063	[2]
Restructuring expenses	0		0		0		6,042
Accretion of asset retirement obligations	860		593		1,704		1,172
Depletion, depreciation and amortization	34,177	[3]	72,112	[3]	75,655	[4]	144,054	[4]
Impairment expense	963		489,599		162,027		490,477
Total costs and expenses	128,899		683,811		412,244		861,003
Operating income (loss)	17,874		(501,480)		(158,914)		(527,978)
Non-operating income (expense):
Loss on derivatives, net	(68,518)		(63,899)		(50,633)		(744)
Income from equity method investee	3,696		2,914		5,994		2,481
Interest expense	(23,512)	[5]	(23,970)	[5]	(47,217)	[6]	(56,384)	[6]
Interest and other income	11		173		110		296
Loss on early redemption of debt	0		(31,537)	[7]	0		(31,537)	[8]
Write-off of debt issuance costs	(842)		0		(842)		0
Loss on disposal of assets, net	(141)		(1,081)		(301)		(1,843)
Non-operating expense, net	(89,306)		(117,400)		(92,889)		(87,731)
Loss before income taxes	(71,432)		(618,880)		(251,803)		(615,709)
Income tax benefit:
Deferred	0		221,846		0		218,203
Total income tax benefit	0		221,846		0		218,203
Net loss	$ (71,432)		$ (397,034)		$ (251,803)		$ (397,506)
Net loss per common share:
Basic (in dollars per share)	$ (0.33)		$ (1.88)		$ (1.17)		$ (2.13)
Diluted (in dollars per share)	$ (0.33)		$ (1.88)		$ (1.17)		$ (2.13)
Weighted-average common shares outstanding:
Basic (in shares)	217,564		211,078		214,562		186,886
Diluted (in shares)	217,564		211,078		214,562		186,886

[1] General and administrative expense was allocated based on the number of employees in the respective segment as of June 30, 2016 and 2015. Certain components of general and administrative expense, primarily payroll, deferred compensation and vehicle expenses, were not allocated but were actual expenses for each segment. Land and geology expenses were not allocated to the midstream and marketing segment.

[2] General and administrative expense was allocated based on the number of employees in the respective segment as of June 30, 2016 and 2015. Certain components of general and administrative expense, primarily payroll, deferred compensation and vehicle expenses, were not allocated but were actual expenses for each segment. Land and geology expenses were not allocated to the midstream and marketing segment.

[3] Depletion, depreciation and amortization were actual expenses for each segment with the exception of the allocation of depreciation of other fixed assets, which is based on the number of employees in the respective segment as of June 30, 2016 and 2015.

[4] Depletion, depreciation and amortization were actual expenses for each segment with the exception of the allocation of depreciation of other fixed assets, which is based on the number of employees in the respective segment as of June 30, 2016 and 2015.

[5] Interest expense was allocated to the exploration and production segment based on gross property and equipment as of June 30, 2016 and 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of June 30, 2016 and 2015.

[6] Interest expense was allocated to the exploration and production segment based on gross property and equipment as of June 30, 2016 and 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of June 30, 2016 and 2015.

[7] Loss on early redemption of debt was allocated to the exploration and production segment based on gross property and equipment as of June 30, 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of June 30, 2015.

[8] Loss on early redemption of debt was allocated to the exploration and production segment based on gross property and equipment as of June 30, 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of June 30, 2015.

XML

Consolidated statement of stockholders' equity - 6 months ended Jun. 30, 2016 - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock	Additional paid-in capital	Treasury Stock (at cost)	Accumulated deficit
Balance, beginning of period at Dec. 31, 2015	$ 131,447	$ 2,138	$ 2,086,652	$ 0	$ (1,957,343)
Balance, beginning of period (in shares) at Dec. 31, 2015		213,808		0
Increase (Decrease) in Stockholders' Equity
Restricted stock awards		$ 30	(30)
Restricted stock awards (in shares)		2,968
Restricted stock forfeitures		$ (2)	2
Restricted stock forfeitures (in shares)		(221)
Vested restricted stock exchanged for tax withholding	(1,541)			$ (1,541)
Vested restricted stock exchanged for tax withholding (in shares)				288
Retirement of treasury stock		$ (3)	(1,538)	$ 1,541
Retirement of treasury stock (in shares)		(288)		(288)
Exercise of employee stock options	67		67
Exercise of employee stock options (in shares)		6
Equity issuance, net of offering costs	119,310	$ 109	119,201
Equity issuance, net of offering costs (in shares)		10,925
Stock-based compensation	11,682		11,682
Net loss	(251,803)				(251,803)
Balance, end of period at Jun. 30, 2016	$ 9,162	$ 2,272	$ 2,216,036	$ 0	$ (2,209,146)
Balance, end of period (in shares) at Jun. 30, 2016		227,198		0

XML

Consolidated statements of cash flows - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Cash flows from operating activities:
Net loss	$ (251,803)	$ (397,506)
Adjustments to reconcile net loss to net cash provided by operating activities:
Deferred income tax benefit	0	(218,203)
Depletion, depreciation and amortization	75,655	144,054
Impairment expense	162,027	490,477
Loss on early redemption of debt	0	31,537	[1]
Non-cash stock-based compensation, net of amounts capitalized	9,911	11,056
Loss on derivatives, net	50,633	744
Cash settlements received for matured derivatives, net	113,319	109,737
Cash settlements received for early terminations of derivatives, net	80,000	0
Change in net present value of deferred premiums paid for derivatives	133	88
Cash premiums paid for derivatives	(84,263)	(2,670)
Amortization of debt issuance costs	2,187	2,501
Write-off of debt issuance costs	842	0
Income from equity method investee	(5,994)	(2,481)
Cash settlement of performance unit awards	(6,394)	(2,738)
Other, net	2,009	3,012
(Increase) decrease in accounts receivable	(844)	16,586
Increase in other assets	(117)	(9,097)
Increase (decrease) in accounts payable	319	(15,744)
Decrease in undistributed revenues and royalties	(9,088)	(20,699)
Increase (decrease) in other accrued liabilities	295	(28,341)
(Decrease) increase in other noncurrent liabilities	(196)	318
Increase in fair value of performance unit awards	0	1,674
Net cash provided by operating activities	138,631	114,305
Capital expenditures:
Oil and natural gas properties	(197,042)	(374,508)
Midstream service assets	(3,425)	(34,137)
Other fixed assets	(832)	(6,541)
Investment in equity method investee	(42,681)	(14,495)
Proceeds from dispositions of capital assets, net of costs	350	35
Net cash used in investing activities	(243,630)	(429,646)
Cash flows from financing activities:
Borrowings on Senior Secured Credit Facility	120,000	300,000
Payments on Senior Secured Credit Facility	(144,682)	(475,000)
Issuance of March 2023 Notes	0	350,000
Redemption of January 2019 Notes	0	(576,200)
Proceeds from issuance of common stock, net of offering costs	119,310	754,163
Purchase of treasury stock	(1,541)	(2,591)
Proceeds from exercise of employee stock options	67	0
Payments for debt issuance costs	0	(6,759)
Net cash provided by financing activities	93,154	343,613
Net (decrease) increase in cash and cash equivalents	(11,845)	28,272
Cash and cash equivalents at beginning of period	31,154	29,321
Cash and cash equivalents at end of period	$ 19,309	$ 57,593

[1] Loss on early redemption of debt was allocated to the exploration and production segment based on gross property and equipment as of June 30, 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of June 30, 2015.

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Organization

6 Months Ended

Jun. 30, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization

Organization

Laredo Petroleum, Inc. ("Laredo"), together with its subsidiaries, Laredo Midstream Services, LLC ("LMS") and Garden City Minerals, LLC ("GCM"), is an independent energy company focused on the acquisition, exploration and development of oil and natural gas properties, and the transportation of oil and natural gas from such properties, primarily in the Permian Basin in West Texas. LMS and GCM (together, the "Guarantors") guarantee all of Laredo's debt instruments. 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.

The Company operates in two business segments: (i) exploration and production and (ii) midstream and marketing. The exploration and production segment is engaged in the acquisition, exploration and development of oil and natural gas properties primarily in the Permian Basin in West Texas. The midstream and marketing segment provides Laredo's exploration and production segment and third parties with products and services that need to be delivered by midstream infrastructure, including oil and natural gas gathering services as well as rig fuel, natural gas lift and water delivery and takeaway in and around Laredo's primary production corridors.

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Basis of presentation and significant accounting policies

6 Months Ended

Jun. 30, 2016

Accounting Policies [Abstract]

Basis of presentation and significant accounting policies

Basis of presentation and significant accounting policies

a.    Basis of presentation

The accompanying unaudited consolidated financial statements were derived from the historical accounting records of the Company and reflect the historical financial position, results of operations and cash flows for the periods described herein. The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). All material intercompany transactions and account balances have been eliminated in the consolidation of accounts. The Company uses the equity method of accounting to record its net interests when the Company holds 20% to 50% of the voting rights and/or has the ability to exercise significant influence but does not control the entity. Under the equity method, the Company's proportionate share of the investee's net income (loss) is included in the unaudited consolidated statements of operations. See Note 14 for additional discussion of the Company's equity method investment.

The accompanying 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, 2015 is derived from audited consolidated financial statements. In the opinion of management, the accompanying unaudited consolidated financial statements reflect all necessary adjustments to present fairly the Company's financial position as of June 30, 2016, results of operations for the three and six months ended June 30, 2016 and 2015 and cash flows for the six months ended June 30, 2016 and 2015.

Certain disclosures have been condensed or omitted from these unaudited consolidated financial statements. Accordingly, these unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in the 2015 Annual Report.

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

The preparation of the accompanying unaudited consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ. The interim results reflected in the unaudited consolidated financial statements are not necessarily indicative of the results that may be expected for other interim periods or for the full year.

Significant estimates include, but are not limited to, (i) estimates of the Company's reserves of oil, NGL and natural gas, (ii) future cash flows from oil and natural gas properties, (iii) depletion, depreciation and amortization, (iv) asset retirement obligations, (v) stock-based compensation, (vi) deferred income taxes, (vii) fair value of assets acquired and liabilities assumed in an acquisition and (viii) fair values of derivatives, deferred premiums and performance unit awards. As fair value is a market-based measurement, it is determined based on the assumptions that would be used by market participants. These estimates and assumptions are based on management's best judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment. Such estimates and assumptions are adjusted when facts and circumstances dictate. Illiquid credit markets and volatile equity and energy markets have combined to increase the uncertainty inherent in such estimates and assumptions. Management believes its estimates and assumptions to be reasonable under the circumstances. As future events and their effects cannot be determined with precision, actual values and results could differ from these estimates. Any changes in estimates resulting from future changes in the economic environment will be reflected in the financial statements in future periods.

c.    Reclassifications

Certain amounts in the accompanying unaudited consolidated financial statements have been reclassified to conform to the 2016 presentation. These reclassifications had no impact to previously reported net loss, stockholders' equity or cash flows.

d.    Accounts receivable

The Company sells produced oil, NGL and natural gas and purchased oil to various customers and participates with other parties in the development and operation of oil and natural gas properties. The Company's accounts receivable are generally unsecured. Accounts receivable for joint interest billings are recorded as amounts billed to customers less an allowance for doubtful accounts.

Joint interest operations amounts are considered past due after 30 days. The Company determines joint interest operations accounts receivable allowances based on management's assessment of the creditworthiness of the joint interest owners. Additionally, as the operator of the majority of its wells, the Company has the ability to realize some or all of the receivables through netting of anticipated future production revenues. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses, current receivables aging and existing industry and economic data. The Company reviews its allowance for doubtful accounts quarterly. Past due amounts greater than 90 days and over a specified amount are reviewed individually for collectability. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is remote.

Accounts receivable consisted of the following components for the periods presented:

(in thousands)	June 30, 2016		December 31, 2015
Oil, NGL and natural gas sales	$	42,629	$	25,582
Joint operations, net(1)	18,425		21,375
Sales of purchased oil and other products	15,000		11,775
Matured derivatives	12,223		27,469
Other	266		1,498
Total	$	88,543	$	87,699

______________________________________________________________________________

(1) Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.2 million as of both June 30, 2016 and December 31, 2015.

e.    Derivatives

The Company uses derivatives to reduce exposure to fluctuations in the prices of oil, NGL and natural gas. By removing a significant portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flows from operations due to fluctuations in commodity prices. These transactions are in the form of puts, swaps, collars and, in prior periods, basis swaps.

Derivatives are recorded at fair value and are presented on a net basis on the unaudited consolidated balance sheets as assets or liabilities. The Company nets the fair value of derivatives by counterparty where the right of offset exists. The Company determines the fair value of its derivatives by utilizing pricing models for substantially similar instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. See Note 9 for discussion regarding the fair value of the Company's derivatives. 

The Company's derivatives were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the unaudited consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities. See Notes 8 and 9 for discussion regarding the Company's derivatives.

f.    Property and equipment

The following table sets forth the Company's property and equipment as of the periods presented:

(in thousands)	June 30, 2016			December 31, 2015
Evaluated oil and natural gas properties	$	5,309,151		$	5,103,635
Less accumulated depletion and impairment	(4,448,482		)	(4,218,942		)
Evaluated oil and natural gas properties, net	860,669			884,693
Unevaluated properties not being depleted	114,507			140,299
Midstream service assets	148,227			147,811
Less accumulated depreciation	(20,175		)	(16,086		)
Midstream service assets, net	128,052			131,725
Depreciable other fixed assets	46,255			46,799
Less accumulated depreciation and amortization	(20,218		)	(18,169		)
Depreciable other fixed assets, net	26,037			28,630
Land	14,914			14,908
Total property and equipment, net	$	1,144,179		$	1,200,255

For the three months ended June 30, 2016 and 2015, depletion expense was $7.06 per barrel of oil equivalent ("BOE") sold and $16.19 per BOE sold, respectively. For the six months ended June 30, 2016 and 2015, depletion expense was $8.01 per BOE sold and $16.13 per BOE sold, respectively.

The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain related employee costs, incurred for the purpose of finding oil, NGL and natural gas are capitalized and depleted on a composite unit of production method based on proved oil, NGL and natural gas reserves. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Costs, including related employee costs, associated with production and general corporate activities are expensed in the period incurred. Sales of oil and natural gas 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 Company excludes the costs directly associated with acquisition and evaluation of unevaluated properties from the depletion calculation until it is determined whether or not proved reserves can be assigned to the properties. The Company capitalizes a portion of its interest costs on its unevaluated properties. Capitalized interest becomes a part of the cost of the unevaluated properties and is subject to depletion when proved reserves can be assigned to the associated properties. All items classified as unevaluated property are assessed on a quarterly basis for possible impairment or reduction in value. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of evaluated reserves and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion.

The full cost ceiling is based principally on the estimated future net revenues from proved oil and natural gas properties discounted at 10%. Per the SEC guidelines, companies are required to use the unweighted arithmetic average first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period before differentials ("Benchmark Prices"). The Benchmark Prices are then adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead ("Realized Prices"). The Realized Prices are utilized to calculate the discounted future net revenues in the full cost ceiling calculation.

In the event the unamortized cost of evaluated oil and natural gas properties being depleted exceeds the full cost ceiling, as defined by the SEC, the excess is charged to expense in the period such excess occurs. Once incurred, a write-down of oil and natural gas properties is not reversible.

The following table presents the Benchmark Prices, Realized Prices and the corresponding non-cash full cost ceiling impairments recorded as of the periods presented:

	For the quarters ended
	June 30, 2016		March 31, 2016		December 31, 2015		September 30, 2015		June 30, 2015
Benchmark Prices
Oil ($/Bbl)	$	39.63	$	42.77	$	46.79	$	55.73	$	68.17
NGL ($/Bbl)	$	17.08	$	17.51	$	18.75	$	21.87	$	26.73
Natural gas ($/MMBtu)	$	2.17	$	2.31	$	2.47	$	2.89	$	3.22
Realized Prices
Oil ($/Bbl)	$	37.96	$	41.33	$	45.58	$	54.28	$	66.68
NGL ($/Bbl)	$	10.80	$	11.25	$	12.50	$	15.25	$	19.56
Natural gas ($/Mcf)	$	1.64	$	1.75	$	1.89	$	2.30	$	2.62
Non-cash full cost ceiling impairment (in thousands)	$	—	$	161,064	$	975,011	$	906,420	$	488,046

Full cost ceiling impairment expense is included in the "Impairment expense" line item in the unaudited consolidated statements of operations and in the financial information provided for the Company's exploration and production segment presented in Note 16.

g. Long-lived assets and inventory

Impairment losses are recorded on property and equipment used in operations and other long-lived assets when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets' carrying amount. Impairment is measured based on the excess of the carrying amount over the fair value of the asset.

Materials and supplies inventory used in developing oil and natural gas properties and midstream service assets are carried at the lower of cost or market ("LCM") with cost determined using the weighted-average cost method and are included in "Other current assets" and "Other assets, net" on the unaudited consolidated balance sheets. The market price for materials and supplies is determined utilizing a replacement cost approach (Level 2).

Beginning at March 31, 2016, frac pit water inventory used in developing oil and natural gas properties is carried at LCM with cost determined using the weighted-average cost method and is included in "Other current assets" on the unaudited consolidated balance sheets. The market price for frac pit water inventory is determined utilizing a replacement cost approach.

The minimum volume of product in a pipeline system that enables the system to operate is known as line-fill and is generally not available to be withdrawn from the pipeline system until the expiration of the transportation contract. The Company owns oil line-fill in third-party pipelines, which is accounted for at LCM with cost determined using the weighted-average cost method and is included in "Other assets, net" on the unaudited consolidated balance sheets. The LCM adjustment is determined utilizing a quoted market price adjusted for regional price differentials (Level 2).

The following table presents inventory impairments recorded as of the periods presented:

	Three months ended June 30,				Six months ended June 30,
(in thousands)	2016		2015		2016		2015
Inventory impairments:
Materials and supplies(1)	$	963	$	1,553	$	963	$	2,320
Line-fill(2)	—		—		—		111
Total inventory impairments	$	963	$	1,553	$	963	$	2,431

______________________________________________________________________________

(1) Included in "Impairment expense" in the unaudited consolidated statements of operations and in "Impairment expense" for the Company's exploration and production segment presented in Note 16.

(2) Included in "Impairment expense" in the unaudited consolidated statements of operations and in "Impairment expense" for the Company's midstream and marketing segment presented in Note 16.

h.    Debt issuance costs

Debt issuance fees, which are recorded at cost, net of amortization, are amortized over the life of the respective debt agreements utilizing the effective interest and straight-line methods. The Company capitalized $6.8 million of debt issuance costs during the six months ended June 30, 2015 mainly as a result of the issuance of the March 2023 Notes (as defined below). No debt issuance costs were capitalized in the six months ended June 30, 2016. The Company had total debt issuance costs of $20.9 million and $23.9 million, net of accumulated amortization of $19.2 million and $17.0 million, as of June 30, 2016 and December 31, 2015, respectively.

The Company wrote-off approximately $0.8 million of debt issuance costs during the six months ended June 30, 2016 as a result of changes in the borrowing base and aggregate elected commitment of the Senior Secured Credit Facility, which are included in the unaudited consolidated statements of operations in the "Write-off of debt issuance costs" line item. During the six months ended June 30, 2015, the Company wrote-off approximately $6.6 million of debt issuance costs as a result of the early redemption of the January 2019 Notes (as defined below), which are included in the unaudited consolidated statements of operations in the "Loss on early redemption of debt" line item. Unamortized debt issuance costs related to the Company's senior unsecured notes are presented in "Long-term debt, net" on the Company's unaudited consolidated balance sheets. Unamortized debt issuance costs related to the Senior Secured Credit Facility are presented in "Other assets, net" on the Company's unaudited consolidated balance sheets. See Note 5.g for additional discussion of debt issuance costs.

Future amortization expense of debt issuance costs as of the period presented is as follows:

(in thousands)	June 30, 2016
Remaining 2016	$	2,092
2017	4,238
2018	4,068
2019	2,915
2020	3,005
Thereafter	4,585
Total	$	20,903

i.    Other current assets and liabilities

Other current assets consist of the following components for the periods presented:

(in thousands)	June 30, 2016		December 31, 2015
Inventory(1)	$	6,986	$	6,974
Prepaid expenses and other	7,459		7,600
Total other current assets	$	14,445	$	14,574

______________________________________________________________________________

(1) See Note 2.g for discussion of inventory held by the Company.

Other current liabilities consist of the following components for the periods presented:

(in thousands)	June 30, 2016		December 31, 2015
Accrued interest payable	$	24,161	$	24,208
Costs of purchased oil payable	15,629		12,189
Lease operating expense payable	11,570		13,205
Accrued compensation and benefits	8,720		14,342
Capital contribution payable to equity method investee(1)	—		27,583
Other accrued liabilities	12,440		14,695
Total other current liabilities	$	72,520	$	106,222

______________________________________________________________________________

(1) See Notes 14 and 15 for additional discussion regarding our equity method investee.

j.    Asset retirement obligations

Asset retirement obligations associated with the retirement of tangible long-lived assets are recognized as a liability in the period in which they are incurred and become determinable. The associated asset retirement costs are part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related long-lived asset is charged to expense through depletion, or for midstream service asset retirement cost through depreciation, of the associated asset. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and as corresponding accretion expense.

The fair value of additions to the asset retirement obligation liability is measured using valuation techniques consistent with the income approach, which converts future cash flows into a single discounted amount. Significant inputs to the valuation include: (i) estimated plug and abandonment cost per well based on Company experience, (ii) estimated remaining life per well, (iii) estimated removal and/or remediation costs for midstream service assets, (iv) estimated remaining life of midstream service assets, (v) future inflation factors and (vi) the Company's average credit adjusted risk-free rate. Inherent in the fair value calculation of asset retirement obligations are numerous assumptions and judgments including, in addition to those noted above, the ultimate settlement of these amounts, the ultimate timing of such settlement and changes in legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing asset retirement obligation liability, a corresponding adjustment will be made to the asset balance.

The Company is obligated by contractual and regulatory requirements to remove certain pipeline assets and perform other remediation of the sites where such pipeline assets are located upon the retirement of those assets. However, the fair value of the asset retirement obligation cannot currently be reasonably estimated because the settlement dates are indeterminate. The Company will record an asset retirement obligation for pipeline assets in the periods in which settlement dates become reasonably determinable.

The following reconciles the Company's asset retirement obligation liability for the periods presented:

(in thousands)	Six months ended June 30, 2016			Year ended December 31, 2015
Liability at beginning of period	$	46,306		$	32,198
Liabilities added due to acquisitions, drilling, midstream service asset construction and other	253			2,236
Accretion expense	1,704			2,423
Liabilities settled upon plugging and abandonment	(526		)	(146		)
Liabilities removed due to sale of property	—			(2,005		)
Revision of estimates(1)	—			11,600
Liability at end of period	$	47,737		$	46,306

_____________________________________________________________________________

(1) The revision of estimates that occurred during the year ended December 31, 2015 is mainly related to a change in the estimated remaining life per well due to the decline in commodity prices.

k.    Fair value measurements

The carrying amounts reported in the unaudited consolidated balance sheets for cash and cash equivalents, accounts receivable, accounts payable, undistributed revenue and royalties, accrued capital expenditures and other accrued assets and liabilities approximate their fair values. See Note 5.f for fair value disclosures related to the Company's debt obligations. The Company carries its derivatives at fair value. See Note 9 for details regarding the fair value of the Company's derivatives.

l.    Treasury stock

Laredo's employees may elect to have the Company withhold shares of stock to satisfy their tax withholding obligations that arise upon the lapse of restrictions on their stock awards. Such treasury stock is recorded at cost and retired upon acquisition.

m.    Compensation awards

Stock-based compensation expense, net of amounts capitalized, is included in "General and administrative" in the unaudited consolidated statements of operations over the awards' vesting periods and is based on the awards' grant date fair value. The Company utilizes the closing stock price on the grant date, less an expected forfeiture rate, to determine the fair value of service vesting restricted stock awards and a Black-Scholes pricing model to determine the fair values of service vesting restricted stock option awards. The Company utilizes a Monte Carlo simulation prepared by an independent third party to determine the fair values of the performance share awards and, in prior periods, the performance unit awards. The Company capitalizes a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration and development of its oil and gas properties into the full cost pool. Capitalized stock-based compensation is included as an addition to "Oil and natural gas properties" in the unaudited consolidated balance sheets. See Note 6 for further discussion regarding the restricted stock awards, restricted stock option awards, performance share awards and performance unit awards.

n.    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 June 30, 2016 or December 31, 2015.

o.    Non-cash investing and supplemental cash flow information

The following presents the non-cash investing and supplemental cash flow information for the periods presented:

	Six months ended June 30,
(in thousands)	2016			2015
Non-cash investing information:
Change in accrued capital expenditures	$	(22,012	)	$	(53,209	)
Change in accrued capital contribution to equity method investee(1)	$	(27,583	)	$	27,917
Capitalized asset retirement cost	$	253		$	1,402
Supplemental cash flow information:
Capitalized interest	$	115		$	178

______________________________________________________________________________

(1) See Notes 14 and 15 for additional discussion regarding our equity method investee.

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Equity offerings

6 Months Ended

Jun. 30, 2016

Equity [Abstract]

Equity Offerings

Equity offerings

On May 16, 2016, the Company completed the sale of 10,925,000 shares of Laredo's common stock (the "May 2016 Equity Offering") for net proceeds of $119.3 million, after underwriting discounts, commissions and offering expenses. See Note 19.e for discussion regarding the completion of an equity offering subsequent to June 30, 2016.

On March 5, 2015, the Company completed the sale of 69,000,000 shares of Laredo's common stock (the "March 2015 Equity Offering") for net proceeds of $754.2 million, after underwriting discounts, commissions and offering expenses. Entities affiliated with Warburg Pincus LLC ("Warburg Pincus") purchased 29,800,000 shares in the March 2015 Equity Offering, following which Warburg Pincus owned 41.0% of Laredo's common stock.

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Divestiture

6 Months Ended

Jun. 30, 2016

Discontinued Operations and Disposal Groups [Abstract]

Divestiture

Divestiture

a. 2015 Divestiture of non-strategic assets

On September 15, 2015, the Company completed the sale of non-strategic and primarily non-operated properties and associated production totaling 6,060 net acres and 123 producing properties in the Midland Basin to a third-party buyer for a purchase price of $65.5 million. After transaction costs reflecting an economic effective date of July 1, 2015, the net proceeds were $64.8 million, net of working capital adjustments and post-closing adjustments. The purchase price, excluding post-closing adjustments, was allocated to oil and natural gas properties pursuant to the rules governing full cost accounting.

Effective at closing, the operations and cash flows of these properties were eliminated from the ongoing operations of the Company, and the Company has no continuing involvement in the properties. This divestiture does not represent a strategic shift and will not have a major effect on the Company's operations or financial results.

The following table presents revenues and expenses of the oil and natural gas properties sold included in the accompanying unaudited consolidated statements of operations for the periods presented:

(in thousands)	Three months ended June 30, 2015		Six months ended June 30, 2015
Oil, NGL and natural gas sales	$	1,970	$	4,048
Expenses(1)	2,098		4,710

_____________________________________________________________________________

(1) Expenses include (i) lease operating expense, (ii) production and ad valorem tax expense, (iii) accretion expense and (iv) depletion expense.

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Debt

6 Months Ended

Jun. 30, 2016

Debt Disclosure [Abstract]

Debt

Debt

a.   March 2023 Notes

On March 18, 2015, the Company completed an offering of $350.0 million in aggregate principal amount of 6 1/4% senior unsecured notes due 2023 (the "March 2023 Notes"). The March 2023 Notes will mature on March 15, 2023 and bear an interest rate of 6 1/4% per annum, payable semi-annually, in cash in arrears on March 15 and September 15 of each year, commencing September 15, 2015. The March 2023 Notes are fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain automatic customary releases, including the sale, disposition or transfer of all of the capital stock or of all or substantially all of the assets of a subsidiary guarantor to one or more persons that are not the Company or a restricted subsidiary, exercise of legal defeasance or covenant defeasance options or satisfaction and discharge of the applicable indenture, designation of a subsidiary guarantor as a non-guarantor restricted subsidiary or as an unrestricted subsidiary in accordance with the applicable indenture, release from guarantee under the Senior Secured Credit Facility, or liquidation or dissolution (collectively, the "Releases").

b.    January 2022 Notes

On January 23, 2014, the Company completed an offering of $450.0 million in aggregate principal amount of 5 5/8% senior unsecured notes due 2022 (the "January 2022 Notes"). The January 2022 Notes will mature on January 15, 2022 and bear an interest rate of 5 5/8% per annum, payable semi-annually, in cash in arrears on January 15 and July 15 of each year, commencing July 15, 2014. The January 2022 Notes are fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain Releases.

c.    May 2022 Notes

On April 27, 2012, the Company completed an offering of $500.0 million in aggregate principal amount of 7 3/8% senior unsecured notes due 2022 (the "May 2022 Notes"). The May 2022 Notes will mature on May 1, 2022 and bear an interest rate of 7 3/8% per annum, payable semi-annually, in cash in arrears on May 1 and November 1 of each year, commencing November 1, 2012. The May 2022 Notes are fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain Releases.

d.    January 2019 Notes

On January 20, 2011, the Company completed an offering of $350.0 million 9 1/2% senior unsecured notes due 2019 (the "January Notes") and on October 19, 2011, the Company completed an offering of an additional $200.0 million 9 1/2% senior unsecured notes due 2019 (the "October Notes" and together with the January Notes, the "January 2019 Notes"). The January 2019 Notes were due to mature on February 15, 2019 and bore an interest rate of 9 1/2% per annum, payable semi-annually, in cash in arrears on February 15 and August 15 of each year. The January 2019 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 April 6, 2015 (the "Redemption Date"), utilizing a portion of the proceeds from the March 2015 Equity Offering and the March 2023 Notes offering, the entire $550.0 million outstanding principal amount of the January 2019 Notes was redeemed at a redemption price of 104.750% of the principal amount of the January 2019 Notes, plus accrued and unpaid interest up to the Redemption Date. The Company recognized a loss on extinguishment of $31.5 million related to the difference between the redemption price and the net carrying amount of the extinguished January 2019 Notes.

e.    Senior Secured Credit Facility

As of June 30, 2016, the Fourth Amended and Restated Credit Agreement (as amended, the "Senior Secured Credit Facility"), which matures on November 4, 2018, had a maximum credit amount of $2.0 billion, a borrowing base and an aggregate elected commitment of $815.0 million with $110.3 million outstanding and was subject to an interest rate of 2.00%. It contains both financial and non-financial covenants, all of which the Company was in compliance with as of June 30, 2016. Laredo is required to pay an annual commitment fee on the unused portion of the financial institutions' commitment of 0.375% to 0.5%, based on the ratio of outstanding revolving credit to the total commitment under the Senior Secured Credit Facility. Additionally, the Senior Secured Credit Facility provides for the issuance of letters of credit, limited to the lesser of total capacity or $20.0 million. No letters of credit were outstanding as of June 30, 2016 or 2015.

See Note 19.a for discussion of additional borrowings and payments on the Senior Secured Credit Facility subsequent to June 30, 2016.

f.    Fair value of debt

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

	June 30, 2016				December 31, 2015
(in thousands)	Long-term debt		Fair value		Long-term debt		Fair value
January 2022 Notes	$	450,000	$	426,564	$	450,000	$	388,301
May 2022 Notes	500,000		501,250		500,000		460,000
March 2023 Notes	350,000		349,965		350,000		301,000
Senior Secured Credit Facility	110,318		110,261		135,000		134,993
Total value of debt	$	1,410,318	$	1,388,040	$	1,435,000	$	1,284,294

The fair values of the debt outstanding on the January 2022 Notes, May 2022 Notes and the March 2023 Notes were determined using the June 30, 2016 and December 31, 2015 quoted market price (Level 1) for each respective instrument. The fair values of the outstanding debt on the Senior Secured Credit Facility as of June 30, 2016 and December 31, 2015 were estimated utilizing pricing models for similar instruments (Level 2). See Note 9 for information about fair value hierarchy levels.

g.    Debt issuance costs

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

	June 30, 2016							December 31, 2015
(in thousands)	Long-term debt		Debt issuance costs, net			Long-term debt, net		Long-term debt		Debt issuance costs, net			Long-term debt, net
January 2022 Notes	$	450,000	$	(5,451	)	$	444,549	$	450,000	$	(5,939	)	$	444,061
May 2022 Notes	500,000		(6,624		)	493,376		500,000		(7,066		)	492,934
March 2023 Notes	350,000		(5,366		)	344,634		350,000		(5,769		)	344,231
Senior Secured Credit Facility(1)	110,318		—			110,318		135,000		—			135,000
Total	$	1,410,318	$	(17,441	)	$	1,392,877	$	1,435,000	$	(18,774	)	$	1,416,226

______________________________________________________________________________

(1) Debt issuance costs related to our Senior Secured Credit Facility are recorded in "Other assets, net" on the unaudited consolidated balance sheets.

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Employee compensation

6 Months Ended

Jun. 30, 2016

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Employee compensation

Employee compensation

The Company has a Long-Term Incentive Plan (the "LTIP"), which provides for the granting of incentive awards in the form of restricted stock awards, restricted stock option awards, performance share awards, performance unit awards and other awards. In the second quarter of 2016, shareholders approved an increase in the maximum number of shares of the Company's common stock issuable under the LTIP from 10,000,000 shares to 24,350,000 shares (the "Amendment").

The Company recognizes the fair value of stock-based compensation awards expected to vest over the requisite service period as a charge against earnings, net of amounts capitalized. The Company's stock-based compensation awards are accounted for as equity instruments, and in prior periods, its performance unit awards were accounted for as liability awards. Stock-based compensation is included in "General and administrative" in the unaudited consolidated statements of operations. The Company capitalizes a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration and development of oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included as an addition to "Oil and natural gas properties" in the unaudited consolidated balance sheets.

a.    Restricted stock awards

All restricted stock awards are treated as issued and outstanding in the accompanying unaudited consolidated financial statements. Per the award agreement terms, if an employee terminates employment prior to the restriction lapse date for reasons other than death or disability, the awarded shares are forfeited and canceled and are no longer considered issued and outstanding. If the employee's termination of employment is by reason of death or disability, all of the holder's restricted stock will automatically vest. Historically, restricted stock awards granted to officers and employees vest in a variety of vesting schedules including (i) 33%, 33% and 34% per year beginning on the first anniversary date of the grant, (ii) 50% in year two and 50% in year three, (iii) fully on the first anniversary of the grant date and (iv) fully on the third anniversary of the grant date. Restricted stock awards granted to non-employee directors vest fully on the first anniversary of the grant date.

The following table reflects the outstanding restricted stock awards for the six months ended June 30, 2016:

(in thousands, except for weighted-average grant date fair values)	Restricted stock awards		Weighted-average grant date fair value (per award)
Outstanding as of December 31, 2015	2,539		$	15.26
Granted	2,968		$	12.27
Forfeited	(221	)	$	15.16
Vested(1)	(1,124	)	$	16.06
Outstanding as of June 30, 2016	4,162		$	12.92

______________________________________________________________________________

(1) The vesting of certain restricted stock awards could result in federal and state income tax expense or benefit related to the difference between the market price of the common stock at the date of vesting and the date of grant. See Note 7 for additional discussion regarding the tax impact of vested stock awards.

The Company utilizes the closing stock price on the grant date to determine the fair value of service vesting restricted stock awards. As of June 30, 2016, unrecognized stock-based compensation related to the restricted stock awards expected to vest was $44.3 million. Such cost is expected to be recognized over a weighted-average period of 2.26 years.

b.    Restricted stock option awards

Restricted stock option awards granted under the LTIP vest and are exercisable in four equal installments on each of the four anniversaries of the grant date. The following table reflects the stock option award activity for the six months ended June 30, 2016:

(in thousands, except for weighted-average price and contractual term)	Restricted stock option awards		Weighted-average  price (per option)		Weighted-average remaining contractual term (years)
Outstanding as of December 31, 2015	1,778		$	17.86	7.91
Granted	1,016		$	4.18
Exercised	(6	)	$	11.93
Expired or canceled	(35	)	$	22.40
Forfeited	(229	)	$	13.62
Outstanding as of June 30, 2016	2,524		$	12.69	8.06
Vested and exercisable at end of period(1)	916		$	19.49	6.41
Expected to vest at end of period(2)	1,600		$	8.75	9.02

_____________________________________________________________________________

(1) The vested and exercisable options as of June 30, 2016 had no aggregate intrinsic value.

(2) The restricted stock options expected to vest as of June 30, 2016 had $6.1 million aggregate intrinsic value.

The Company utilizes the Black-Scholes option pricing model to determine the fair value of restricted stock option awards and recognizes the associated expense on a straight-line basis over the four-year requisite service period of the awards. Determining the fair value of equity-based awards requires judgment, including estimating the expected term that stock option awards will be outstanding prior to exercise and the associated volatility. As of June 30, 2016, unrecognized stock-based compensation related to restricted stock option awards expected to vest was $13.5 million. Such cost is expected to be recognized over a weighted-average period of 2.55 years.

The assumptions used to estimate the fair value of the 22,324 restricted stock options granted on April 1, 2016 and the 994,022 restricted stock options granted on May 25, 2016 are as follows:

	April 1, 2016			May 25, 2016
Risk-free interest rate(1)	1.44		%	1.58		%
Expected option life(2)	6.25 years			6.25 years
Expected volatility(3)	61.34		%	61.94		%
Fair value per stock option	$	4.44		$	9.75

(1) United States Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, correlating the treasury yield terms to the expected life of the option.

(2) As the Company had limited exercise history at the time of valuation relating to terminations and modifications, expected option life assumptions were developed using the simplified method in accordance with GAAP.

(3) The Company utilized its own historical volatility in order to develop the expected volatility.     

In accordance with the LTIP and stock option agreement, the options granted will become exercisable in accordance with the following schedule based upon the number of full years of the optionee's continuous employment or service with the Company, following the date of grant:

Full years of continuous employment	Incremental percentage of option exercisable		Cumulative percentage of option exercisable
Less than one	—	%	—	%
One	25	%	25	%
Two	25	%	50	%
Three	25	%	75	%
Four	25	%	100	%

No shares of common stock may be purchased unless the optionee has remained in continuous employment with the Company for one year from the grant date. Unless terminated sooner, the option will expire if and to the extent it is not exercised within 10 years from the grant date. The unvested portion of a stock option award shall expire upon termination of employment, and the vested portion of a stock option award shall remain exercisable for (i) one year following termination of employment by reason of the holder's death or disability, but not later than the expiration of the option period, or (ii) 90 days following termination of employment for any reason other than the holder's death or disability, and other than the holder's termination of employment for cause. Both the unvested and the vested but unexercised portion of a stock option award shall expire upon the termination of the option holder's employment or service by the Company for cause.

c.    Performance share awards

The performance share awards granted to management in the second quarter of 2016 (the "2016 Performance Share Awards"), February 27, 2015 (the "2015 Performance Share Awards") and on February 27, 2014 (the "2014 Performance Share Awards") are subject to a combination of market and service vesting criteria. A Monte Carlo simulation prepared by an independent third party was utilized to determine the grant date fair value of these awards. The Company has determined these awards are equity awards and recognizes the associated expense on a straight-line basis over the three-year requisite service period of the awards. These awards will be settled, if at all, in stock at the end of the requisite service period based on the achievement of certain performance criteria.

The 1,742,469 outstanding 2016 Performance Share Awards have a performance period of January 1, 2016 to December 31, 2018, and any shares earned under such awards are expected to be issued in the first quarter of 2019 if the performance criteria are met. The 475,518 outstanding 2015 Performance Share Awards have a performance period of January 1, 2015 to December 31, 2017, and any shares earned under such awards are expected to be issued in the first quarter of 2018 if the performance criteria are met. The 210,126 outstanding 2014 Performance Share Awards have a performance period of January 1, 2014 to December 31, 2016, and any shares earned under such awards are expected to be issued in the first quarter of 2017 if the performance criteria are met.

The following table reflects the performance share award activity for the six months ended June 30, 2016:

(in thousands, except for weighted-average grant date fair values)	Performance share awards		Weighted-average grant date fair value (per award)
Outstanding as of December 31, 2015	874		$	20.06
Granted	1,801		$	17.71
Forfeited	(247	)	$	19.69
Vested	—		$	—
Outstanding as of June 30, 2016	2,428		$	18.36

As of June 30, 2016, unrecognized stock-based compensation related to the performance share awards was $35.3 million. Such cost is expected to be recognized over a weighted-average period of 2.47 years.

The assumptions used to estimate the fair value of the 32,495 performance share awards granted on April 1, 2016 and the 1,768,297 performance share awards granted on May 25, 2016 are as follows:

	April 1, 2016			May 25, 2016
Risk-free rate(1)	0.87		%	1.02		%
Dividend yield	—		%	—		%
Expected volatility(2)	71.54		%	74.73		%
Laredo stock closing price on grant date	$	7.71		$	12.36
Fair value per performance share	$	9.83		$	17.86

______________________________________________________________________________

(1) The risk-free rate was derived using a term-matched zero-coupon yield derived from the Treasury Constant Maturities yield curve on the grant date.

(2) The Company utilized its own historical volatility over a lookback period equal to the length of the remaining performance period from the grant date in order to develop the expected volatility.

d.    Stock-based compensation award expense

The following has been recorded to stock-based compensation expense for the periods presented:

	Three months ended June 30,						Six months ended June 30,
(in thousands)	2016			2015			2016			2015
Restricted stock award compensation	$	4,692		$	4,520		$	8,460		$	7,458
Restricted stock option award compensation	777			1,279			1,401			1,949
Restricted performance share award compensation	1,593			1,378			1,821			2,273
Total stock-based compensation, gross	7,062			7,177			11,682			11,680
Less amounts capitalized in oil and natural gas properties	(989		)	(909		)	(1,771		)	(624		)
Total stock-based compensation, net of amounts capitalized	$	6,073		$	6,268		$	9,911		$	11,056

e.    Performance unit awards

The performance unit awards issued to management on February 15, 2013 (the "2013 Performance Unit Awards") and on February 3, 2012 (the "2012 Performance Unit Awards") were subject to a combination of market and service vesting criteria. These awards were accounted for as liability awards as they were settled in cash at the end of the requisite service period based on the achievement of certain performance criteria.

The 44,481 settled 2013 Performance Unit Awards had a performance period of January 1, 2013 to December 31, 2015 and, as their performance criteria were satisfied, they were paid at $143.75 per unit during the first quarter of 2016. The 27,381 settled 2012 Performance Unit Awards had a performance period of January 1, 2012 to December 31, 2014 and, as their performance criteria were satisfied, they were paid at $100.00 per unit during the first quarter of 2015.

For the three and six months ended June 30, 2015, compensation expense for the 2013 Performance Unit Awards is included in "General and administrative" in the Company's unaudited consolidated statements of operations, and as of December 31, 2015, the corresponding liability is included in "Other current liabilities" on the unaudited consolidated balance sheets. Due to the quarterly re-measurement of the fair value of the 2013 Performance Unit Awards as of June 30, 2015, compensation expense for the three and six months ended June 30, 2015 was $0.7 million and $1.7 million, respectively.

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Income taxes

6 Months Ended

Jun. 30, 2016

Income Tax Disclosure [Abstract]

Income taxes

Income taxes

Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating losses and tax credit carry-forwards. Under this method, deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income (loss) in the period that includes the enactment date.

The Company evaluates uncertain tax positions for recognition and measurement in the unaudited consolidated financial statements. To recognize a tax position, the Company determines whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more-likely-than-not threshold is measured to determine the amount of benefit to be recognized in the unaudited consolidated financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. The Company had no unrecognized tax benefits related to uncertain tax positions in the unaudited consolidated financial statements as of June 30, 2016 or December 31, 2015.

The Company is subject to federal and state income taxes and the Texas franchise tax. Income tax benefit for the periods presented consisted of the following:

	Three months ended June 30,				Six months ended June 30,
(in thousands)	2016		2015		2016		2015
Current taxes	$	—	$	—	$	—	$	—
Deferred taxes	—		221,846		—		218,203
Income tax benefit	$	—	$	221,846	$	—	$	218,203

Income tax benefit differed from amounts computed by applying the applicable federal income tax rate of 35% to pre-tax earnings as a result of the following:

	Three months ended June 30,						Six months ended June 30,
(in thousands)	2016			2015			2016			2015
Income tax benefit computed by applying the statutory rate	$	25,001		$	216,608		$	88,131		$	215,498
State income tax and change in valuation allowance	(541		)	5,776			187			5,867
Non-deductible stock-based compensation	—			(15		)	—			(106		)
Stock-based compensation tax deficiency	(190		)	(381		)	(4,012		)	(2,838		)
Increase in deferred tax valuation allowance	(24,323		)	(11		)	(84,218		)	(16		)
Other items	53			(131		)	(88		)	(202		)
Income tax benefit	$	—		$	221,846		$	—		$	218,203

For the three and six months ended June 30, 2016, the effective tax rate was not meaningful due to the valuation allowance recorded. For the three and six months ended June 30, 2015, the effective tax rate was 36% and 35%, respectively. The Company's effective tax rate is affected by changes in valuation allowances, recurring permanent differences and by discrete items that may occur in any given year, but are not consistent from year to year.

A valuation allowance is established to reduce deferred tax assets if it is determined that it is more likely than not that the related tax benefit will not be realized. On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances, if necessary. During the year ended December 31, 2015 and the six months ended June 30, 2016, in evaluating whether it was more likely than not that the Company's net deferred tax assets were realizable through future net income, management considered all available positive and negative evidence, including (i) its earnings history, (ii) its ability to recover net operating loss carry-forwards, (iii) the existence of significant proved oil, NGL and natural gas reserves, (iv) its ability to use tax planning strategies, (v) its current price protection utilizing oil and natural gas hedges, (vi) its future revenue and operating cost projections and (vii) the current market prices for oil, NGL and natural gas. Based on all the evidence available, during the year ended December 31, 2015, management determined it was more likely than not that the net deferred tax assets were not realizable, and therefore recorded a valuation allowance of $676.0 million. During the six months ended June 30, 2016, an additional valuation allowance of $83.7 million was recorded.

The impact of significant discrete items is separately recognized in the quarter in which the discrete items occur. The vesting of certain restricted stock awards could result in federal and state income tax expense or benefits related to the difference between the market price of the common stock at the date of vesting and the grant date. The exercise of stock option awards could result in federal and state income tax expense or benefits related to the difference between the fair value of the stock option at the grant date and the intrinsic value of the stock option when exercised. The tax impact resulting from vestings of restricted stock awards and exercise of option awards are discrete items. During the three and six months ended June 30, 2016 and 2015, certain shares related to restricted stock awards vested at times when the Company's stock price was lower than the fair value of those shares at the time of the grant. As a result, the income tax deduction related to such shares is less than the expense previously recognized for book purposes. During the three and six months ended June 30, 2016, certain stock options were exercised. No stock options were exercised during the three and six months ended June 30, 2015. The income tax deduction related to the intrinsic value of the options was less than the expense previously recognized for book purposes. In accordance with GAAP, such shortfalls reduce additional paid-in capital to the extent windfall tax benefits have been previously recognized. However, the Company has not previously recognized any windfall tax benefits. Therefore, such shortfalls are included in income tax expense.

The following table presents the tax impact of these shortfalls for the periods presented:

	Three months ended June 30,						Six months ended June 30,
(in thousands)	2016			2015			2016			2015
Vesting of restricted stock	$	(182	)	$	(388	)	$	(4,057	)	$	(2,889	)
Exercise of restricted stock options	(10		)	—			(10		)	—
Tax expense due to shortfalls	$	(192	)	$	(388	)	$	(4,067	)	$	(2,889	)

Significant components of the Company's net deferred tax asset for the periods presented are as follows:

(in thousands)	June 30, 2016			December 31, 2015
Oil and natural gas properties, midstream service assets and other fixed assets	$	282,612		$	306,997
Net operating loss carry-forward	528,625			479,022
Derivatives	(41,577		)	(98,675		)
Stock-based compensation	9,340			11,597
Equity method investee	(25,612		)	(31,711		)
Accrued bonus	2,544			4,763
Capitalized interest	2,173			2,525
Other	2,901			2,820
Net deferred tax asset before valuation allowance	761,006			677,338
Valuation allowance	(761,006		)	(677,338		)
Net deferred tax asset	$	—		$	—

The Company had federal net operating loss carry-forwards totaling $1.5 billion and state of Oklahoma net operating loss carry-forwards totaling $41.0 million as of June 30, 2016. These carry-forwards begin expiring in 2026. Additionally, these carry-forwards include windfall tax deductions from vestings of certain restricted stock awards and stock option exercises that were not recorded in the Company's income tax provision. The amount of windfall tax benefit recognized in additional paid-in capital is limited to the amount of benefit realized currently in income taxes payable. As of June 30, 2016, the Company had suspended additional paid-in capital credits of $4.5 million related to windfall tax deductions. Upon realization of the net operating loss carry-forwards from such windfall tax deductions, the Company would record a benefit of up to $4.5 million in additional paid-in capital.

The Company's income tax returns for the years 2012 through 2015 remain open and subject to examination by federal tax authorities and/or the tax authorities in Oklahoma and Texas, which are the jurisdictions where the Company has or had operations. Additionally, the statute of limitations for examination of federal net operating loss carry-forwards typically does not begin to run until the year the attribute is utilized in a tax return.

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Derivatives

6 Months Ended

Jun. 30, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives

Derivatives

a. Derivatives

The Company engages in derivative transactions such as puts, swaps, collars and, in prior periods, basis swaps to hedge price risks due to unfavorable changes in oil and natural gas prices related to its production. As of June 30, 2016, the Company had 25 open derivative contracts with financial institutions that extend from July 2016 to December 2018. None of these contracts were designated as hedges for accounting purposes. The contracts are recorded at fair value on the unaudited consolidated balance sheets and gains and losses are recognized in current period earnings. Gains and losses on derivatives are reported on the unaudited consolidated statements of operations on the "Gain (loss) on derivatives, net" line item.

Each put transaction has an established floor price. The Company pays its counterparty a premium, which can be deferred until settlement, to enter into the put transaction. When the settlement price is below the floor price, the counterparty pays the Company an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the floor price, the put option expires.

Each swap transaction has an established fixed price. When the settlement price is below the fixed price, the counterparty pays the Company an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the fixed price, the Company pays its counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume.

Each collar transaction has an established price floor and ceiling. When the settlement price is below the price floor established by these collars, the Company receives an amount from its counterparty equal to the difference between the settlement price and the price floor multiplied by the hedged contract volume. When the settlement price is above the price ceiling established by these collars, the Company pays its counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the hedged contract volume.

In the prior year, the oil basis swap transactions had an established fixed basis differential. The Company's oil basis swaps' differential was between the West Texas Intermediate-Argus Americas Crude (Midland) ("WTI Midland") index crude oil price and the West Texas Intermediate NYMEX ("WTI NYMEX") index crude oil price. When the WTI NYMEX price less the fixed basis differential was greater than the actual WTI Midland price, the difference multiplied by the hedged contract volume was paid to the Company by the counterparty. When the WTI NYMEX price less the fixed basis differential was less than the actual WTI Midland price, the difference multiplied by the hedged contract volume was paid by the Company to the counterparty.

During the six months ended June 30, 2016, the Company successfully completed a hedge restructuring by early terminating the floors of certain derivative contract collars that resulted in a termination amount of $80 million, which was settled in full by applying the proceeds to prepay the premiums on two new derivatives entered into during the restructuring.

During the six months ended June 30, 2016, the following derivatives were terminated:

	Aggregate volumes	Floor price		Contract period
Oil (volumes in Bbl):
Put portion of the associated collars	2,263,000	$	80.00	January 2017 - December 2017

During the six months ended June 30, 2016, the following derivatives were entered into:

	Aggregate volumes	Floor price		Ceiling price		Contract period
Oil (volumes in Bbl):
Put(1)	2,263,000	$	60.00	$	—	January 2017 - December 2017
Put(2)	2,098,750	$	60.00	$	—	January 2017 - December 2018
Put(3)	600,000	$	40.00	$	—	May 2016 - December 2016
Swap	1,095,000	$	52.12	$	—	January 2018 - December 2018
Natural gas (volumes in MMBtu):(4)
Put	8,040,000	$	2.50	$	—	January 2017 - December 2017
Put	8,220,000	$	2.50	$	—	January 2018 - December 2018
Collar	5,256,000	$	2.50	$	3.05	January 2017 - December 2017
Collar	4,635,500	$	2.50	$	3.60	January 2018 - December 2018

_____________________________________________________________________________

(1) As part of the Company's hedge restructuring, this put replaced the early terminated put portion of the restructured derivative contract collars. A premium of $40.0 million was paid at contract inception.

(2) As part of the Company's hedge restructuring, a premium of $40.0 million was paid at contract inception.

(3) There are $1.2 million in deferred premiums associated with this contract.

(4) There are $5.1 million in deferred premiums associated with these contracts.

The following represents cash settlements received for derivatives, net for the periods presented:

	Three months ended June 30,				Six months ended June 30,
(in thousands)	2016		2015		2016		2015
Cash settlements received for matured derivatives, net	$	47,382	$	46,596	$	113,319	$	109,737
Cash settlements received for early terminations of derivatives, net(1)	—		—		80,000		—
Cash settlements received for derivatives, net	$	47,382	$	46,596	$	193,319	$	109,737

_____________________________________________________________________________

(1) The settlements amount for the six months ended June 30, 2016 includes $4.0 million in deferred premiums which were settled net with the early terminated contracts from which they derive.

The following table summarizes open positions as of June 30, 2016, and represents, as of such date, derivatives in place through December 2018 on annual production volumes:

	Remaining year 2016		Year 2017		Year 2018
Oil positions:(1)
Puts:
Hedged volume (Bbl)	1,098,000		1,049,375		1,049,375
Weighted-average price ($/Bbl)	$	42.95	$	60.00	$	60.00
Swaps:
Hedged volume (Bbl)	791,200		—		1,095,000
Weighted-average price ($/Bbl)	$	84.82	$	—	$	52.12
Collars:
Hedged volume (Bbl)	1,833,500		2,628,000		—
Weighted-average floor price ($/Bbl)	$	73.98	$	60.00	$	—
Weighted-average ceiling price ($/Bbl)	$	89.62	$	97.22	$	—
Totals:
Total volume hedged with floor price (Bbl)	3,722,700		3,677,375		2,144,375
Weighted-average floor price ($/Bbl)	$	67.13	$	60.00	$	55.98
Total volume hedged with ceiling price (Bbl)	2,624,700		2,628,000		1,095,000
Weighted-average ceiling price ($/Bbl)	$	88.18	$	97.22	$	52.12
Natural gas positions:(2)
Puts:
Hedged volume (MMBtu)	—		8,040,000		8,220,000
Weighted-average price ($/MMBtu)	$	—	$	2.50	$	2.50
Collars:
Hedged volume (MMBtu)	9,384,000		10,731,000		4,635,500
Weighted-average floor price ($/MMBtu)	$	3.00	$	2.76	$	2.50
Weighted-average ceiling price ($/MMBtu)	$	5.60	$	3.53	$	3.60
Totals:
Total volume hedged with floor price (MMBtu)	9,384,000		18,771,000		12,855,500
Weighted-average floor price ($/MMBtu)	$	3.00	$	2.65	$	2.50
Total volume hedged with ceiling price (MMBtu)	9,384,000		10,731,000		4,635,500
Weighted-average ceiling price ($/MMBtu)	$	5.60	$	3.53	$	3.60

_______________________________________________________________________________

(1) Oil derivatives are settled based on the average of the daily settlement prices for the First Nearby Month of the WTI NYMEX Light Sweet Crude Oil Futures Contract for each NYMEX Trading Day during each month.

(2) Natural gas derivatives are settled based on the Inside FERC index price for West Texas Waha for the calculation period.

b. Balance sheet presentation

In accordance with the Company's standard practice, its derivatives are subject to counterparty netting under agreements governing such derivatives. The Company's oil and natural gas derivatives are presented on a net basis as "Derivatives" on the unaudited consolidated balance sheets. See Note 9.a for a summary of the fair value of derivatives on a gross basis.

By using derivatives to hedge exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk. For the Company, market risk is the exposure to changes in the market price of oil and natural gas, which are subject to fluctuations from a variety of factors, including changes in supply and demand. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, thereby creating credit risk. The Company's counterparties are participants in the Senior Secured Credit Facility, which is secured by the Company's oil and natural gas reserves; therefore, the Company is not required to post any collateral. The Company does not require collateral from its derivative counterparties. The Company minimizes the credit risk in derivatives by: (i) limiting its exposure to any single counterparty, (ii) entering into derivatives only with counterparties that meet the Company's minimum credit quality standard or have a guarantee from an affiliate that meets the Company's minimum credit quality standard and (iii) monitoring the creditworthiness of the Company's counterparties on an ongoing basis.

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Fair value measurements

6 Months Ended

Jun. 30, 2016

Fair Value Disclosures [Abstract]

Fair value measurements

Fair value measurements

The Company accounts for its oil and natural gas derivatives at fair value. The fair value of derivatives is determined utilizing pricing models for similar instruments. The models use a variety of techniques to arrive at fair value, including quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward curves generated from a compilation of data gathered from third parties.

The Company has categorized its assets and liabilities measured at fair value, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).

Assets and liabilities recorded at fair value on the unaudited consolidated balance sheets are categorized based on inputs to the valuation techniques as follows: 

Level 1—	Assets and liabilities recorded at fair value for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access. Active markets are considered to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2—	Assets and liabilities recorded at fair value for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the assets or liabilities. Substantially all of these inputs are observable in the marketplace throughout the full term of the price risk management instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace.
Level 3—	Assets and liabilities recorded at fair value for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. Unobservable inputs are not corroborated by market data. These inputs reflect management's own assumptions about the assumptions a market participant would use in pricing the asset or liability.

When the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety. The Company conducts a review of fair value hierarchy classifications on an annual basis. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities. Transfers between fair value hierarchy levels are recognized and reported in the period in which the transfer occurred. No transfers between fair value hierarchy levels occurred during the three or six months ended June 30, 2016 or 2015.

a. Fair value measurement on a recurring basis

The following tables summarize the Company's fair value hierarchy by commodity on a gross basis and the net presentation on the unaudited consolidated balance sheets for derivative assets and liabilities measured at fair value on a recurring basis as of the periods presented:

(in thousands)	Level 1		Level 2			Level 3			Total gross fair value			Amounts offset			Net fair value presented on the unaudited consolidated balance sheets
As of June 30, 2016:
Assets
Current:
Oil derivatives	$	—	$	93,057		$	—		$	93,057		$	(515	)	$	92,542
Natural gas derivatives	—		3,458			—			3,458			(1,165		)	2,293
Oil deferred premiums	—		—			—			—			(5,467		)	(5,467		)
Natural gas deferred premiums	—		—			—			—			(403		)	(403		)
Noncurrent:
Oil derivatives	$	—	$	33,181		$	—		$	33,181		$	—		$	33,181
Natural gas derivatives	—		2,724			—			2,724			(2,724		)	—
Oil deferred premiums	—		—			—			—			(501		)	(501		)
Natural gas deferred premiums	—		—			—			—			—			—
Liabilities
Current:
Oil derivatives	$	—	$	—		$	—		$	—		$	515		$	515
Natural gas derivatives	—		(739		)	—			(739		)	1,165			426
Oil deferred premiums	—		—			(6,784		)	(6,784		)	5,467			(1,317		)
Natural gas deferred premiums	—		—			(1,507		)	(1,507		)	403			(1,104		)
Noncurrent:
Oil derivatives	$	—	$	(1,820	)	$	—		$	(1,820	)	$	—		$	(1,820	)
Natural gas derivatives	—		(774		)	—			(774		)	2,724			1,950
Oil deferred premiums	—		—			(501		)	(501		)	501			—
Natural gas deferred premiums	—		—			(3,870		)	(3,870		)	—			(3,870		)
Net derivative position	$	—	$	129,087		$	(12,662	)	$	116,425		$	—		$	116,425

(in thousands)	Level 1		Level 2		Level 3			Total gross fair value			Amounts offset			Net fair value presented on the unaudited consolidated balance sheets
As of December 31, 2015:
Assets
Current:
Oil derivatives	$	—	$	194,940	$	—		$	194,940		$	—		$	194,940
Natural gas derivatives	—		13,166		—			13,166			—			13,166
Oil deferred premiums	—		—		—			—			(9,301		)	(9,301		)
Natural gas deferred premiums	—		—		—			—			—			—
Noncurrent:
Oil derivatives	$	—	$	80,302	$	—		$	80,302		$	—		$	80,302
Natural gas derivatives	—		2,459		—			2,459			—			2,459
Oil deferred premiums	—		—		—			—			(4,877		)	(4,877		)
Natural gas deferred premiums	—		—		—			—			(441		)	(441		)
Liabilities
Current:
Oil derivatives	$	—	$	—	$	—		$	—		$	—		$	—
Natural gas derivatives	—		—		—			—			—			—
Oil deferred premiums	—		—		(9,301		)	(9,301		)	9,301			—
Natural gas deferred premiums	—		—		—			—			—			—
Noncurrent:
Oil derivatives	$	—	$	—	$	—		$	—		$	—		$	—
Natural gas derivatives	—		—		—			—			—			—
Oil deferred premiums	—		—		(4,877		)	(4,877		)	4,877			—
Natural gas deferred premiums	—		—		(441		)	(441		)	441			—
Net derivative position	$	—	$	290,867	$	(14,619	)	$	276,248		$	—		$	276,248

These items are included as "Derivatives" on the unaudited consolidated balance sheets. Significant Level 2 assumptions associated with the calculation of discounted cash flows used in the mark-to-market analysis of derivatives include each derivative contract's corresponding commodity index price, appropriate risk-adjusted discount rates and other relevant data.

The Company's deferred premiums associated with its derivative contracts are categorized as Level 3, as the Company utilizes a net present value calculation to determine the valuation. They are considered to be measured on a recurring basis as the derivative contracts they derive from are measured on a recurring basis. As derivative contracts containing deferred premiums are entered into, the Company discounts the associated deferred premium to its net present value at the contract trade date, using the Senior Secured Credit Facility rate at the trade date (historical input rates range from 1.69% to 3.56%), and then records the change in net present value to interest expense over the period from trade until the final settlement date at the end of the contract. After this initial valuation, the net present value of each deferred premium is not adjusted; therefore, significant increases (decreases) in the Senior Secured Credit Facility rate would result in a significantly lower (higher) fair value measurement for each new contract entered into that contained a deferred premium; however, the valuation for the deferred premiums already recorded would remain unaffected. While the Company believes the sources utilized to arrive at the fair value estimates are reliable, different sources or methods could have yielded different fair value estimates; therefore, on a quarterly basis, the valuation is compared to counterparty valuations and a third-party valuation of the deferred premiums for reasonableness.

The following table presents actual cash payments required for deferred premiums for the calendar years presented:

(in thousands)	June 30, 2016
Remaining 2016	$	5,407
2017	5,354
2018	2,100
Total	$	12,861

A summary of the changes in assets classified as Level 3 measurements for the periods presented are as follows:

	Three months ended June 30,						Six months ended June 30,
(in thousands)	2016			2015			2016			2015
Balance of Level 3 at beginning of period	$	(13,054	)	$	(8,882	)	$	(14,619	)	$	(9,285	)
Change in net present value of deferred premiums for derivatives	(61		)	(45		)	(133		)	(88		)
Total purchases and settlements:
Purchases	(1,960		)	(4,409		)	(6,072		)	(5,384		)
Settlements(1)	2,413			1,249			8,162			2,670
Balance of Level 3 at end of period	$	(12,662	)	$	(12,087	)	$	(12,662	)	$	(12,087	)

_____________________________________________________________________________

(1) The amount for the six months ended June 30, 2016 includes $3.9 million which represents the present value of deferred premiums settled in the Company's restructuring upon their early termination.

b. Fair value measurement on a nonrecurring basis

The Company accounts for the impairment of long-lived assets and inventory, if any, at fair value on a nonrecurring basis. For purposes of fair value measurement, it was determined that the impairment of long-lived assets and inventory are classified as Level 3, based on the use of internally developed cash flow models. See Note 2.g for discussion regarding the Company's impairment of (i) materials and supplies for the three months ended June 30, 2016 and the three and six months ended June 30, 2015 and (ii) line-fill for the six months ended June 30, 2015.

The accounting policies for impairment of oil and natural gas properties are discussed in Note 2.f. Significant inputs included in the calculation of discounted cash flows used in the impairment analysis include the Company's estimate of operating and development costs, anticipated production of evaluated reserves and other relevant data. See Note 2.f for discussion regarding the prices used in the calculation of discounted cash flows and the Company's first-quarter 2016 and second-quarter 2015 full cost ceiling impairments.

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Net loss per share

6 Months Ended

Jun. 30, 2016

Earnings Per Share [Abstract]

Net loss per share

Net loss per share

Basic net loss per share is computed by dividing net loss by the weighted-average number of common shares outstanding for the period. Diluted net loss per share reflects the potential dilution of non-vested restricted stock awards, performance share awards and outstanding restricted stock options. For the three and six months ended June 30, 2016 and 2015, all of these potentially dilutive items were anti-dilutive due to the Company's net loss and, therefore, were excluded from the calculation of diluted net loss per share.

The following is the calculation of basic and diluted weighted-average common shares outstanding and net loss per share for the periods presented:

	Three months ended June 30,						Six months ended June 30,
(in thousands, except for per share data)	2016			2015			2016			2015
Net loss (numerator):
Net loss—basic and diluted	$	(71,432	)	$	(397,034	)	$	(251,803	)	$	(397,506	)
Weighted-average common shares outstanding (denominator):
Basic	217,564			211,078			214,562			186,886
Diluted	217,564			211,078			214,562			186,886
Net loss per share:
Basic	$	(0.33	)	$	(1.88	)	$	(1.17	)	$	(2.13	)
Diluted	$	(0.33	)	$	(1.88	)	$	(1.17	)	$	(2.13	)

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Credit risk

6 Months Ended

Jun. 30, 2016

Risks and Uncertainties [Abstract]

Credit risk

Credit risk

The Company's oil, NGL and natural gas sales are made to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. The Company's joint operations accounts receivable are from a number of oil and natural gas companies, partnerships, individuals and others who own interests in the oil and natural gas properties operated by the Company. The Company's sales of purchased oil are made to one customer. Management believes that any credit risk imposed by a concentration in the oil and natural gas industry is offset by the creditworthiness of the Company's customer base and industry partners. The Company routinely assesses the recoverability of all material trade and other receivables to determine collectability.

The Company uses derivatives to hedge its exposure to oil and natural gas price volatility. These transactions expose the Company to potential credit risk from its counterparties. In accordance with the Company's standard practice, its derivatives are subject to counterparty netting under agreements governing such derivatives; therefore, the credit risk associated with its derivative counterparties is somewhat mitigated. See Notes 2.e, 8 and 9 for additional information regarding the Company's derivatives.

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Commitments and contingencies

6 Months Ended

Jun. 30, 2016

Commitments and Contingencies Disclosure [Abstract]

Commitments and contingencies

Commitments and contingencies

a.    Litigation

From time to time the Company is involved in legal proceedings and/or may be subject to industry rulings that could bring rise to claims in the ordinary course of business. The Company has concluded that the likelihood is remote that the ultimate resolution of any pending litigation or pending claims will be material or have a material adverse effect on the Company's business, financial position, results of operations or liquidity.

b.    Drilling contract

The Company has committed to several drilling contracts with a third party to facilitate the Company's drilling plans. One of these contracts is for a term of multiple months and contains an early termination clause that requires the Company to potentially pay penalties to the third party should the Company cease drilling efforts. This penalty would negatively impact the Company's financial statements upon early contract termination. The future commitment of $3.0 million as of June 30, 2016 is not recorded in the accompanying unaudited consolidated balance sheets. Management does not currently anticipate the early termination of this contract in 2016.

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 minimal volume penalties. These commitments are normal and customary for the Company's business. Future commitments of $400.2 million as of June 30, 2016 are not recorded in the accompanying unaudited consolidated balance sheets. The Company's production has been equivalent or greater than its delivery commitments during the most recent year, and management expects such production will continue to exceed the Company's future commitments. However, 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. Also, if production is not sufficient to satisfy the Company's delivery commitments, the Company can and may use spot market purchases to fulfill the commitments.

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.    Other commitments

See Notes 2.i, 15.a and 19.b for the amount of and discussion regarding the commitments to the Company's non-consolidated variable interest entity ("VIE").

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Restructuring

6 Months Ended

Jun. 30, 2016

Restructuring and Related Activities [Abstract]

Restructuring

2015 Restructuring

Following the fourth-quarter 2014 drop in oil prices, in an effort to reduce costs and to better position the Company for ongoing efficient growth, on January 20, 2015, the Company executed a company-wide restructuring and reduction in force (the "RIF") that included (i) the relocation of certain employees from the Company's Dallas, Texas area office to the Company's other existing offices in Tulsa, Oklahoma and Midland, Texas; (ii) closing the Company's Dallas, Texas area office; (iii) a workforce reduction of approximately 75 employees and (iv) the release of 24 contract personnel. The RIF was communicated to employees on January 20, 2015 and was generally effective immediately. The Company's compensation committee approved the RIF and the related severance package. The Company incurred $6.0 million in expenses during the six months ended June 30, 2015 related to the RIF. There were no comparative amounts recorded in the six months ended June 30, 2016.

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Variable interest entity

6 Months Ended

Jun. 30, 2016

Equity Method Investments and Joint Ventures [Abstract]

Variable interest entity

Variable interest entity

An entity is referred to as a VIE pursuant to accounting guidance for consolidation if it possesses one of the following criteria: (i) it is thinly capitalized, (ii) the residual equity holders do not control the entity, (iii) the equity holders are shielded from the economic losses, (iv) the equity holders do not participate fully in the entity's residual economics, or (v) the entity was established with non-substantive voting interests. In order to determine if a VIE should be consolidated, an entity must determine if it is the primary beneficiary of the VIE. The primary beneficiary of a VIE is that variable interest-holder possessing a controlling financial interest through: (i) its power to direct the activities of the VIE that most significantly impact the VIE's economic performance and (ii) its obligation to absorb losses or its right to receive benefits from the VIE that could potentially be significant to the VIE. In order to determine whether the Company owns a variable interest in a VIE, a qualitative analysis is performed of the entity's design, organizational structure, primary decision makers and relevant agreements. The Company continually monitors its VIE exposure to determine if any events have occurred that could cause the primary beneficiary to change.

LMS contributed $16.0 million and $42.7 million during the three and six months ended June 30, 2016, respectively, and $14.5 million during the six months ended June 30, 2015, to Medallion Gathering & Processing, LLC, a Texas limited liability company formed on October 12, 2012, and its wholly-owned subsidiaries (together "Medallion"). See Note 19.b for discussion regarding a contribution made to Medallion subsequent to June 30, 2016.

LMS holds 49% of Medallion's ownership units. Medallion was established for the purpose of developing midstream solutions and providing midstream infrastructure to bring oil, NGL and natural gas to market. LMS and the other 51% interest-holder have agreed that the voting rights of Medallion, the profit and loss sharing, and the additional capital contribution requirements shall be equal to the ownership unit percentage held. Additionally, Medallion requires a super-majority vote of 75% for all key operating and business decisions. The Company has determined that Medallion is a VIE. However, LMS is not considered to be the primary beneficiary of the VIE because LMS does not have the power to direct the activities that most significantly affect Medallion's economic performance. As such, Medallion is accounted for under the equity method of accounting with the Company's proportionate share of Medallion's net income reflected in the unaudited consolidated statements of operations as "Income from equity method investee" and the carrying amount reflected in the unaudited consolidated balance sheets as "Investment in equity method investee."

During the six months ended June 30, 2016 and 2015, Medallion continued expansion activities on existing portions of its pipeline infrastructure in order to gather and transport additional third-party oil production. During the three months ended June 30, 2015, Medallion began recognizing revenue due to its main pipeline becoming fully operational. See Note 15.a for discussion of items included in the Company's unaudited consolidated financial statements related to Medallion.

During the three months ended June 30, 2015, the Company negotiated a buyout of a minimum volume commitment to Medallion, which was related to natural gas gathering infrastructure Medallion constructed on acreage that the Company does not plan to develop. The portion of the buyout that was related to the Company's minimum volume commitment for future periods was $3.0 million and is included in the unaudited consolidated statements of operations in the line item "Minimum volume commitments" for the period in which the buyout was settled.

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Related Parties

6 Months Ended

Jun. 30, 2016

Related Party Transactions [Abstract]

Related Parties

Related Parties

a.    Medallion

The following table summarizes items included in the unaudited consolidated statements of operations related to Medallion for the periods presented:

	Three months ended June 30,				Six months ended June 30,
(in thousands)	2016		2015		2016		2015
Midstream service revenues	$	—	$	390	$	—	$	487
Minimum volume commitments	—		3,579		—		5,235
Interest and other income	—		—		—		108

The following table summarizes items included in the unaudited consolidated balance sheets related to Medallion as of the dates presented:

(in thousands)	June 30, 2016		December 31, 2015
Accounts receivable, net	$	—	$	1,163
Other assets, net(1)	1,025		1,025
Other current liabilities(2)	102		27,583

______________________________________________________________________________

(1) Amounts included in "Other assets, net" above represent LMS owned line-fill in Medallion's pipeline.

(2) Amounts included in "Other current liabilities" above represent LMS' accrued line-fill purchase in Medallion's pipeline as of June 30, 2016 and capital contribution payable to Medallion as of December 31, 2015.

b.    Targa Resources Corp.

The Company has a gathering and processing arrangement with affiliates of Targa Resources Corp. ("Targa"). One of Laredo's directors was on the board of directors of Targa until May 18, 2015.

The following table summarizes the oil, NGL and natural gas sales and midstream service revenues received from Targa included in the unaudited consolidated statements of operations for the periods presented:

	Three months ended June 30,				Six months ended June 30,
(in thousands)	2016		2015		2016		2015
Oil, NGL and natural gas sales	$	18,112	$	34,012	$	35,917	$	53,643
Midstream service revenues	102		—		237		—

The following table summarizes the amounts included in accounts receivable, net from Targa in the unaudited consolidated balance sheets as of the dates presented:

(in thousands)	June 30, 2016		December 31, 2015
Accounts receivable, net	$	9,337	$	6,097

c.    Archrock Partners, L.P.

The Company has a compression arrangement with affiliates of Archrock Partners, L.P., formerly Exterran Partners L.P. ("Archrock"). One of Laredo's directors is on the board of directors of Archrock GP LLC, an affiliate of Archrock.

The following table summarizes the lease operating expenses related to Archrock included in the unaudited consolidated statements of operations for the periods presented:

	Three months ended June 30,				Six months ended June 30,
(in thousands)	2016		2015		2016		2015
Lease operating expenses	$	526	$	391	$	1,001	$	776

The following table summarizes the capital expenditures related to Archrock included in the unaudited consolidated statements of cash flows for the periods presented:

	Three months ended June 30,				Six months ended June 30,
(in thousands)	2016		2015		2016		2015
Capital expenditures:
Midstream service assets	$	—	$	18	$	20	$	64

The following table summarizes the amounts included in accounts payable from Archrock in the unaudited consolidated balance sheets as of the dates presented:

(in thousands)	June 30, 2016		December 31, 2015
Accounts payable	$	—	$	13

d.    Helmerich & Payne, Inc.

The Company has had drilling contracts with Helmerich & Payne, Inc. ("H&P"). Laredo's Chairman and Chief Executive Officer is on the board of directors of H&P.

The following table summarizes the capitalized oil and natural gas properties related to H&P included in the unaudited consolidated statements of cash flows for the periods presented:

	Three months ended June 30,				Six months ended June 30,
(in thousands)	2016		2015		2016		2015
Capital expenditures:
Oil and natural gas properties	$	—	$	177	$	—	$	2,434

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Segments

6 Months Ended

Jun. 30, 2016

Segment Reporting [Abstract]

Segments

Segments

The Company operates in two business segments: (i) exploration and production and (ii) midstream and marketing. The exploration and production segment is engaged in the acquisition, exploration and development of oil and natural gas properties primarily in the Permian Basin in West Texas. The midstream and marketing segment provides Laredo's exploration and production segment and third parties with products and services that need to be delivered by midstream infrastructure, including oil and natural gas gathering services as well as rig fuel, natural gas lift and water delivery and takeaway in and around Laredo's primary production corridors.

The following table presents selected financial information, for the periods presented, regarding the Company's operating segments on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis:

(in thousands)	Exploration and production			Midstream and marketing			Eliminations			Consolidated company
Three months ended June 30, 2016:
Oil, NGL and natural gas sales	$	102,526		$	—		$	—		$	102,526
Midstream service revenues	—			11,138			(9,506		)	1,632
Sales of purchased oil	—			42,615			—			42,615
Total revenues	102,526			53,753			(9,506		)	146,773
Lease operating expenses, including production tax	29,793			—			(2,586		)	27,207
Midstream service expenses	—			6,572			(5,394		)	1,178
Costs of purchased oil	—			44,012			—			44,012
General and administrative(1)	18,818			1,684			—			20,502
Depletion, depreciation and amortization(2)	31,969			2,208			—			34,177
Impairment expense	963			—			—			963
Other operating costs and expenses(3)	806			54			—			860
Operating income (loss)	$	20,177		$	(777	)	$	(1,526	)	$	17,874
Other financial information:
Income from equity method investee	$	—		$	3,696		$	—		$	3,696
Interest expense(4)	$	(22,050	)	$	(1,462	)	$	—		$	(23,512	)
Capital expenditures	$	(92,089	)	$	(1,488	)	$	—		$	(93,577	)
Gross property and equipment(6)	$	5,484,416		$	366,858		$	(4,604	)	$	5,846,670
Three months ended June 30, 2015:
Oil, NGL and natural gas sales	$	125,679		$	221		$	(346	)	$	125,554
Midstream service revenues	—			4,362			(2,636		)	1,726
Sales of purchased oil	—			55,051			—			55,051
Total revenues	125,679			59,634			(2,982		)	182,331
Lease operating expenses, including production tax	41,423			—			(2,717		)	38,706
Midstream service expenses, including minimum volume commitments	4,399			998			(221		)	5,176
Costs of purchased oil	—			54,417			—			54,417
General and administrative(1)	21,347			1,861			—			23,208
Depletion, depreciation and amortization(2)	69,987			2,125			—			72,112
Impairment expense	489,599			—			—			489,599
Other operating costs and expenses(3)	548			45			—			593
Operating income (loss)	$	(501,624	)	$	188		$	(44	)	$	(501,480	)
Other financial information:
Income from equity method investee	$	—		$	2,914		$	—		$	2,914
Interest expense(4)	$	(22,845	)	$	(1,125	)	$	—		$	(23,970	)
Loss on early redemption of debt(5)	$	(30,056	)	$	(1,481	)	$	—		$	(31,537	)
Capital expenditures	$	(133,259	)	$	(13,841	)	$	—		$	(147,100	)
Gross property and equipment(6)	$	5,170,912		$	257,073		$	(365	)	$	5,427,620

_______________________________________________________________________________

(1) General and administrative expense was allocated based on the number of employees in the respective segment as of June 30, 2016 and 2015. Certain components of general and administrative expense, primarily payroll, deferred compensation and vehicle expenses, were not allocated but were actual expenses for each segment. Land and geology expenses were not allocated to the midstream and marketing segment.

(2) Depletion, depreciation and amortization were actual expenses for each segment with the exception of the allocation of depreciation of other fixed assets, which is based on the number of employees in the respective segment as of June 30, 2016 and 2015.

(3) Other operating costs and expenses consist of accretion of asset retirement obligations. These are actual costs and expenses and were not allocated.

(4) Interest expense was allocated to the exploration and production segment based on gross property and equipment as of June 30, 2016 and 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of June 30, 2016 and 2015.

(5) Loss on early redemption of debt was allocated to the exploration and production segment based on gross property and equipment as of June 30, 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of June 30, 2015.

(6) Gross property and equipment for the midstream and marketing segment includes investment in equity method investee totaling $213.6 million and $103.2 million as of June 30, 2016 and 2015, respectively. Other fixed assets were allocated based on the number of employees in the respective segment as of June 30, 2016 and 2015.

(in thousands)	Exploration and production			Midstream and marketing			Eliminations			Consolidated company
Six months ended June 30, 2016:
Oil, NGL and natural gas sales	$	175,668		$	—		$	—		$	175,668
Midstream service revenues	—			22,405			(18,972		)	3,433
Sales of purchased oil	—			74,229			—			74,229
Total revenues	175,668			96,634			(18,972		)	253,330
Lease operating expenses, including production tax	59,157			—			(4,997		)	54,160
Midstream service expenses	—			13,081			(11,294		)	1,787
Costs of purchased oil	—			76,958			—			76,958
General and administrative(1)	36,497			3,456			—			39,953
Depletion, depreciation and amortization(2)	71,261			4,394			—			75,655
Impairment expense	162,027			—			—			162,027
Other operating costs and expenses(3)	1,598			106			—			1,704
Operating loss	$	(154,872	)	$	(1,361	)	$	(2,681	)	$	(158,914	)
Other financial information:
Income from equity method investee	$	—		$	5,994		$	—		$	5,994
Interest expense(4)	$	(44,353	)	$	(2,864	)	$	—		$	(47,217	)
Capital expenditures	$	(197,874	)	$	(3,425	)	$	—		$	(201,299	)
Gross property and equipment(6)	$	5,484,416		$	366,858		$	(4,604	)	$	5,846,670
Six months ended June 30, 2015:
Oil, NGL and natural gas sales	$	243,890		$	333		$	(551	)	$	243,672
Midstream service revenues	—			8,045			(5,010		)	3,035
Sales of purchased oil	—			86,318			—			86,318
Total revenues	243,890			94,696			(5,561		)	333,025
Lease operating expenses, including production tax	85,268			—			(5,096		)	80,172
Midstream service expenses, including minimum volume commitments	4,399			4,340			(333		)	8,406
Costs of purchased oil	—			85,617			—			85,617
General and administrative(1)	41,125			3,938			—			45,063
Depletion, depreciation and amortization(2)	140,244			3,810			—			144,054
Impairment expense	490,366			111			—			490,477
Other operating costs and expenses(3)	6,972			242			—			7,214
Operating loss	$	(524,484	)	$	(3,362	)	$	(132	)	$	(527,978	)
Other financial information:
Income from equity method investee	$	—		$	2,481		$	—		$	2,481
Interest expense(4)	$	(53,932	)	$	(2,452	)	$	—		$	(56,384	)
Loss on early redemption of debt(5)	$	(30,056	)	$	(1,481	)	$	—		$	(31,537	)
Capital expenditures	$	(380,872	)	$	(34,314	)	$	—		$	(415,186	)
Gross property and equipment(6)	$	5,170,912		$	257,073		$	(365	)	$	5,427,620

_______________________________________________________________________________

(1) General and administrative expense was allocated based on the number of employees in the respective segment as of June 30, 2016 and 2015. Certain components of general and administrative expense, primarily payroll, deferred compensation and vehicle expenses, were not allocated but were actual expenses for each segment. Land and geology expenses were not allocated to the midstream and marketing segment.

(2) Depletion, depreciation and amortization were actual expenses for each segment with the exception of the allocation of depreciation of other fixed assets, which is based on the number of employees in the respective segment as of June 30, 2016 and 2015.

(3) Other operating costs and expenses consist of accretion of asset retirement obligations for the six months ended June 30, 2016 and 2015 and restructuring expense for the six months ended June 30, 2015. These are actual costs and expenses and were not allocated.

(4) Interest expense was allocated to the exploration and production segment based on gross property and equipment as of June 30, 2016 and 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of June 30, 2016 and 2015.

(5) Loss on early redemption of debt was allocated to the exploration and production segment based on gross property and equipment as of June 30, 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of June 30, 2015.

(6) Gross property and equipment for the midstream and marketing segment includes investment in equity method investee totaling $213.6 million and $103.2 million as of June 30, 2016 and 2015, respectively. Other fixed assets were allocated based on the number of employees in the respective segment as of June 30, 2016 and 2015.

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Subsidiary guarantors

6 Months Ended

Jun. 30, 2016

Condensed Financial Information of Parent Company Only Disclosure [Abstract]

Subsidiary guarantors

Subsidiary guarantors

The Guarantors have fully and unconditionally guaranteed the January 2022 Notes, the May 2022 Notes, the March 2023 Notes and the Senior Secured Credit Facility (and had guaranteed the January 2019 Notes until the Redemption Date), subject to the Releases. In accordance with practices accepted by the SEC, Laredo has prepared condensed consolidating financial statements to quantify the assets, results of operations and cash flows of such subsidiaries as subsidiary guarantors. The following unaudited condensed consolidating balance sheets as of June 30, 2016 and December 31, 2015, unaudited condensed consolidating statements of operations for the three and six months ended June 30, 2016 and 2015 and unaudited condensed consolidating statements of cash flows for the six months ended June 30, 2016 and 2015 present financial information for Laredo on a stand-alone basis (carrying any investment in subsidiaries under the equity method), financial information for the subsidiary guarantors on a stand-alone basis (carrying any investment in subsidiaries under the equity method), and the consolidation and elimination entries necessary to arrive at the information for the Company on a condensed consolidated basis. Deferred income taxes for LMS and for GCM are recorded on Laredo's statements of financial position, statements of operations and statements of cash flows as they are disregarded entities for income tax purposes. Laredo and the Guarantors are not restricted from making intercompany distributions to each other. During the six months ended June 30, 2016, certain assets were transferred from LMS to Laredo at historical cost. See Note 5.d for a discussion of the early redemption of the January 2019 Notes.

Condensed consolidating balance sheet

June 30, 2016

(Unaudited)

(in thousands)	Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Accounts receivable, net	$	73,429	$	15,114	$	—		$	88,543
Other current assets	120,982		1,737		—			122,719
Total oil and natural gas properties, net	970,445		9,335		(4,604		)	975,176
Total midstream service assets, net	—		128,052		—			128,052
Total other fixed assets, net	40,701		250		—			40,951
Investment in subsidiaries and equity method investee	348,623		213,616		(348,623		)	213,616
Total other long-term assets	37,526		3,568		—			41,094
Total assets	$	1,591,706	$	371,672	$	(353,227	)	$	1,610,151
Accounts payable	$	12,934	$	1,566	$	—		$	14,500
Other current liabilities	120,756		18,556		—			139,312
Long-term debt, net	1,392,877		—		—			1,392,877
Other long-term liabilities	51,373		2,927		—			54,300
Stockholders' equity	13,766		348,623		(353,227		)	9,162
Total liabilities and stockholders' equity	$	1,591,706	$	371,672	$	(353,227	)	$	1,610,151

Condensed consolidating balance sheet

December 31, 2015

(Unaudited)

(in thousands)	Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Accounts receivable, net	$	74,613	$	13,086	$	—		$	87,699
Other current assets	244,477		56		—			244,533
Total oil and natural gas properties, net	1,017,565		9,350		(1,923		)	1,024,992
Total midstream service assets, net	—		131,725		—			131,725
Total other fixed assets, net	43,210		328		—			43,538
Investment in subsidiaries and equity method investee	301,891		192,524		(301,891		)	192,524
Total other long-term assets	84,360		3,916		—			88,276
Total assets	$	1,766,116	$	350,985	$	(303,814	)	$	1,813,287
Accounts payable	$	12,203	$	1,978	$	—		$	14,181
Other current liabilities	158,283		44,351		—			202,634
Long-term debt, net	1,416,226		—		—			1,416,226
Other long-term liabilities	46,034		2,765		—			48,799
Stockholders' equity	133,370		301,891		(303,814		)	131,447
Total liabilities and stockholders' equity	$	1,766,116	$	350,985	$	(303,814	)	$	1,813,287

Condensed consolidating statement of operations

For the three months ended June 30, 2016

(Unaudited)

(in thousands)	Laredo			Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Total revenues	$	102,511		$	53,768	$	(9,506	)	$	146,773
Total costs and expenses	84,137			52,742		(7,980		)	128,899
Operating income	18,374			1,026		(1,526		)	17,874
Interest expense and other, net	(23,501		)	—		—			(23,501		)
Other non-operating income (expense)	(64,779		)	3,692		(4,718		)	(65,805		)
Income (loss) before income tax	(69,906		)	4,718		(6,244		)	(71,432		)
Income tax	—			—		—			—
Net income (loss)	$	(69,906	)	$	4,718	$	(6,244	)	$	(71,432	)

Condensed consolidating statement of operations

For the six months ended June 30, 2016

(Unaudited)

(in thousands)	Laredo			Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Total revenues	$	175,633		$	96,669	$	(18,972	)	$	253,330
Total costs and expenses	334,201			94,334		(16,291		)	412,244
Operating income (loss)	(158,568		)	2,335		(2,681		)	(158,914		)
Interest expense and other, net	(47,107		)	—		—			(47,107		)
Other non-operating income (expense)	(43,447		)	5,983		(8,318		)	(45,782		)
Income (loss) before income tax	(249,122		)	8,318		(10,999		)	(251,803		)
Income tax	—			—		—			—
Net income (loss)	$	(249,122	)	$	8,318	$	(10,999	)	$	(251,803	)

Condensed consolidating statement of operations

For the three months ended June 30, 2015

(Unaudited)

(in thousands)	Laredo			Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Total revenues	$	125,687		$	59,626	$	(2,982	)	$	182,331
Total costs and expenses	629,359			57,390		(2,938		)	683,811
Operating income (loss)	(503,672		)	2,236		(44		)	(501,480		)
Interest expense and other, net	(23,797		)	—		—			(23,797		)
Other non-operating income (expense)	(91,367		)	2,914		(5,150		)	(93,603		)
Income (loss) before income tax	(618,836		)	5,150		(5,194		)	(618,880		)
Deferred income tax benefit	221,846			—		—			221,846
Net income (loss)	$	(396,990	)	$	5,150	$	(5,194	)	$	(397,034	)

Condensed consolidating statement of operations

For the six months ended June 30, 2015

(Unaudited)

(in thousands)	Laredo			Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Total revenues	$	243,833		$	94,753	$	(5,561	)	$	333,025
Total costs and expenses	772,667			93,765		(5,429		)	861,003
Operating income (loss)	(528,834		)	988		(132		)	(527,978		)
Interest expense and other, net	(56,088		)	—		—			(56,088		)
Other non-operating income (expense)	(30,655		)	2,481		(3,469		)	(31,643		)
Income (loss) before income tax	(615,577		)	3,469		(3,601		)	(615,709		)
Deferred income tax benefit	218,203			—		—			218,203
Net income (loss)	$	(397,374	)	$	3,469	$	(3,601	)	$	(397,506	)

Condensed consolidating statement of cash flows

For the six months ended June 30, 2016

(Unaudited)

(in thousands)	Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Net cash flows provided by operating activities	$	139,610		$	7,339		$	(8,318	)	$	138,631
Change in investment between affiliates	(47,069		)	38,751			8,318			—
Capital expenditures and other	(197,540		)	(46,090		)	—			(243,630		)
Net cash flows provided by financing activities	93,154			—			—			93,154
Net decrease in cash and cash equivalents	(11,845		)	—			—			(11,845		)
Cash and cash equivalents at beginning of period	31,153			1			—			31,154
Cash and cash equivalents at end of period	$	19,308		$	1		$	—		$	19,309

Condensed consolidating statement of cash flows

For the six months ended June 30, 2015

(Unaudited)

(in thousands)	Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Net cash flows provided by (used in) operating activities	$	136,092		$	(18,318	)	$	(3,469	)	$	114,305
Change in investment between affiliates	(70,472		)	67,003			3,469			—
Capital expenditures and other	(380,961		)	(48,685		)	—			(429,646		)
Net cash flows provided by financing activities	343,613			—			—			343,613
Net increase in cash and cash equivalents	28,272			—			—			28,272
Cash and cash equivalents at beginning of period	29,320			1			—			29,321
Cash and cash equivalents at end of period	$	57,592		$	1		$	—		$	57,593

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Recent accounting pronouncements

6 Months Ended

Jun. 30, 2016

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Recent accounting pronouncements

Recent accounting pronouncements

In March, April and May 2016,the Financial Accounting Standards Board ("FASB"), issued new guidance in Topic 606, Revenue from Contracts with Customers, to address the following potential implementation issues of the new revenue standard: (a) to clarify the implementation guidance on principal versus agent considerations, (b) to clarify the identification of performance obligations and the licensing implementation guidance and (c) to address certain issues in the guidance on assessing collectibility, presentation of sales taxes, noncash consideration, and completed contracts and contract modifications at transition. The effective date and transition requirements for the amendments in these updates are the same as the effective date and transition requirements for the guidance issued in May 2014 and August 2015 to Topic 606. These updates are effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company is currently evaluating the impact this guidance will have on its consolidated financial statements upon adoption of this standard.

In March 2016, the FASB issued new guidance in Topic 323, Investments—Equity Method and Joint Ventures, to eliminate the requirement to retroactively adopt the equity method of accounting when an investment qualifies for use of the equity method as a result of an increase in the level of ownership interest or degree of influence. The amendments in this update are effective for annual periods beginning after December 15, 2016 and interim periods within those annual periods. The amendments in this update should be applied prospectively upon their effective date to increases in the level of ownership interest or degree of influence that result in the adoption of the equity method. Early application of the amendments in this update is permitted. The Company is currently evaluating the impact this guidance will have on its consolidated financial statements upon adoption of this standard.

In March 2016, the FASB issued new guidance in Topic 718, Compensation—Stock Compensation, which seeks to simplifythe income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. The amendments in this update are effective for annual periods beginning after December 15, 2016 and interim periods within those annual periods. Early adoption is permitted for any entity in any interim or annual period. If an entity early adopts the amendments in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the applicable amendments in the same period. The Company is currently evaluating the impact this guidance will have on its consolidated financial statements upon adoption of this standard.

In February 2016, the FASB issued new guidance in Topic 842, Leases. The core principle of the new guidance is that a lessee should recognize the assets and liabilities that arise from leases in the statement of financial position. A lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. When measuring assets and liabilities arising from a lease, a lessee (and a lessor) should include payments to be made in optional periods only if the lessee is reasonably certain to exercise an option to extend the lease or not to exercise an option to terminate the lease. Similarly, optional payments to purchase the underlying asset should be included in the measurement of lease assets and lease liabilities only if the lessee is reasonably certain to exercise that purchase option. Reasonably certain is a high threshold that is consistent with and intended to be applied in the same way as the reasonably assured threshold in the previous leases guidance. In addition, also consistent with the previous leases guidance, a lessee (and a lessor) should exclude most variable lease payments in measuring lease assets and lease liabilities, other than those that depend on an index or a rate or are in substance fixed payments. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. If a lessee makes this election, it should recognize lease expense for such leases generally on a straight-line basis over the lease term. The recognition, measurement and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from previous GAAP. There continues to be a differentiation between finance leases and operating leases. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. These practical expedients relate to the identification and classification of leases that commenced before the effective date, initial direct costs for leases that commenced before the effective date and the ability to use hindsight in evaluating lessee options to extend or terminate a lease or to purchase the underlying asset. An entity that elects to apply the practical expedients will, in effect, continue to account for leases that commence before the effective date in accordance with previous GAAP unless the lease is modified, except that lessees are required to recognize a right-of-use asset and a lease liability for all operating leases at each reporting date based on the present value of the remaining minimum rental payments that were tracked and disclosed under previous GAAP. The amendments in this update are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application of the amendments in this update is permitted. The Company is currently evaluating the impact this guidance will have on its consolidated financial statements upon adoption of this standard.

In July 2015, the FASB issued new guidance in Topic 330, Inventory, which seeks to simplify the measurement of inventory. The amendments in this update apply to inventory that is measured using all methods excluding last-in, first-out and the retail inventory method. The main substantive provision of this guidance is for an entity to change the subsequent measurement of inventory, within the scope of this guidance, from LCM to the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. The amendments in this update are effective for annual reporting periods beginning after December 15, 2016, including interim periods within those fiscal years and should be applied prospectively with earlier application permitted as of the beginning of an interim or annual reporting period. The Company is currently evaluating the impact this guidance will have on its consolidated financial statements upon adoption of this standard.

In April 2015, the FASB issued new guidance in Subtopic 350-40, Intangibles—Goodwill and Other—Internal-Use Software. The amendments in this update provide guidance to customers about whether a cloud computing arrangement includes a software license. If a cloud computing arrangement includes a software license, then the customer should account for the software license element of the arrangement consistent with the acquisition of other software licenses. If a cloud computing arrangement does not include a software license, the customer should account for the arrangement as a service contract. The guidance will not change GAAP for a customer's accounting for service contracts. In addition, the guidance in this update supersedes paragraph 350-40-25-16. The amendments in this update are effective for annual periods beginning after December 15, 2015, including interim periods within those annual periods and should be applied prospectively to all arrangements entered into or materially modified after the effective date or retrospectively. The Company elected to adopt this guidance in the first quarter of 2016 on a prospective basis, and the adoption did not have an effect on its unaudited consolidated financial statements.

In May 2014, the FASB issued a comprehensive new revenue recognition standard that supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities—Oil and Gas—Revenue Recognition. The core principle of the new guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for transferring those goods or services. The new standard also requires significantly expanded disclosure regarding the qualitative and quantitative information of an entity's nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The standard creates a five-step model that requires companies to exercise judgment when considering the terms of a contract and all relevant facts and circumstances. The standard allows for several transition methods: (a) a full retrospective adoption in which the standard is applied to all of the periods presented, or (b) a modified retrospective adoption in which the standard is applied only to the most current period presented in the financial statements, including additional disclosures of the standard's application impact to individual financial statement line items. This standard is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company is currently evaluating the impact this guidance will have on its consolidated financial statements upon adoption of this standard.

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Subsequent events

6 Months Ended

Jun. 30, 2016

Subsequent Events [Abstract]

Subsequent events

Subsequent events

a.   Senior Secured Credit Facility

On July 12, 2016, the Company borrowed $94.7 million on the Senior Secured Credit Facility, after which the outstanding balance under the Senior Secured Credit Facility was $205.0 million. On July 19, 2016, the Company completed the July 2016 Equity Offering (as defined below) and applied the net proceeds to the outstanding balance under the Senior Secured Credit Facility, reducing the balance to $70.0 million.

b.  Medallion contribution

Subsequent to June 30, 2016, the Company approved, and on July 29, 2016 contributed, $16.0 million to fund continued expansion activities on existing portions of Medallion's pipeline infrastructure in order to gather additional third-party production. See Note 14 for additional discussion regarding Medallion and see Note 15.a for discussion of items included in the Company's unaudited consolidated financial statements related to Medallion.

c.    New derivative contracts

Subsequent to June 30, 2016, the Company entered into the following new derivative contracts:

	Aggregate volumes	Price		Contract period
Oil (volumes in Bbl):(1)
Swap	1,003,750	$	51.90	January 2017 - December 2017
Swap	1,003,750	$	51.17	January 2017 - December 2017
NGL (volumes in Bbl):
Swap(2)	444,000	$	11.24	January 2017 - December 2017
Swap(3)	375,000	$	22.26	January 2017 - December 2017

_____________________________________________________________

(1) The associated derivatives will be settled based on the WTI NYMEX index oil price.

(2) The associated derivative will be settled based on the Mont Belvieu Purity Ethane-OPIS price.

(3) The associated derivative will be settled based on the Mont Belvieu Propane (TET)-OPIS price.

d.   Acquisition of proved and unproved oil and natural gas properties

Subsequent to June 30, 2016, the Company entered into an agreement to acquire approximately 9,200 net acres of additional leasehold interests in western Glasscock and Reagan counties within the Company's core development area (which includes production of approximately 300 net BOE/D from existing vertical wells) for an aggregate purchase price of $125.0 million. On July 13 and July 18, 2016, the Company closed portions of this acquisition for approximately $92.7 million and $1.65 million, respectively. The closings on the remaining interests, which are subject to certain preferential purchase rights and consents, are expected to occur as such rights and consents are satisfied or obtained during the third and fourth quarters of 2016.

e.   July equity offering

On July 19, 2016, the Company completed the sale of 13,000,000 shares of Laredo's common stock (the "July 2016 Equity Offering") for net proceeds of approximately $136.3 million, after underwriting discounts, commissions and offering expenses. The Company used the net proceeds from the July 2016 Equity Offering to repay borrowings under its Senior Secured Credit Facility as discussed above in Note 19.a. The Company granted the underwriters a 30-day option to purchase up to an additional 1,950,000 shares of Laredo's common stock on the same terms. On August 4, 2016, the underwriters provided notice of the full exercise of the option. The sale of the additional 1,950,000 shares of Laredo’s common stock pursuant to the option is expected to close on August 9, 2016 and will result in net proceeds to the Company of approximately $20.5 million, after underwriting discounts, commissions and offering expenses.

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Supplementary information

6 Months Ended

Jun. 30, 2016

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Supplementary information

Supplementary information

Costs incurred in oil, NGL and natural gas property acquisition, exploration and development activities

Costs incurred in the acquisition, exploration and development of oil, NGL and natural gas assets are presented below:

	Three months ended June 30,				Six months ended June 30,
(in thousands)	2016		2015		2016		2015
Property acquisition costs:							—
Evaluated	$	—	$	—	$	—	$	—
Unevaluated	—		—		—		—
Exploration	19,769		3,841		27,032		8,354
Development costs(1)	70,806		110,518		152,692		317,190
Total costs incurred	$	90,575	$	114,359	$	179,724	$	325,544

____________________________________________________________________________

(1) The costs incurred for oil, NGL and natural gas development activities include$0.1 million and $0.5 millionin asset retirement obligations for thethree months ended June 30, 2016 and 2015, respectively, and $0.2 million and $1.0 million for the six months ended June 30, 2016 and 2015, respectively.

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Basis of presentation and significant accounting policies (Policies)

6 Months Ended

Jun. 30, 2016

Accounting Policies [Abstract]

Basis of presentation

Basis of presentation

The accompanying unaudited consolidated financial statements were derived from the historical accounting records of the Company and reflect the historical financial position, results of operations and cash flows for the periods described herein. The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). All material intercompany transactions and account balances have been eliminated in the consolidation of accounts. The Company uses the equity method of accounting to record its net interests when the Company holds 20% to 50% of the voting rights and/or has the ability to exercise significant influence but does not control the entity. Under the equity method, the Company's proportionate share of the investee's net income (loss) is included in the unaudited consolidated statements of operations. See Note 14 for additional discussion of the Company's equity method investment.

The accompanying 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, 2015 is derived from audited consolidated financial statements. In the opinion of management, the accompanying unaudited consolidated financial statements reflect all necessary adjustments to present fairly the Company's financial position as of June 30, 2016, results of operations for the three and six months ended June 30, 2016 and 2015 and cash flows for the six months ended June 30, 2016 and 2015.

Certain disclosures have been condensed or omitted from these unaudited consolidated financial statements. Accordingly, these unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in the 2015 Annual Report.

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

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

The preparation of the accompanying unaudited consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ. The interim results reflected in the unaudited consolidated financial statements are not necessarily indicative of the results that may be expected for other interim periods or for the full year.

Significant estimates include, but are not limited to, (i) estimates of the Company's reserves of oil, NGL and natural gas, (ii) future cash flows from oil and natural gas properties, (iii) depletion, depreciation and amortization, (iv) asset retirement obligations, (v) stock-based compensation, (vi) deferred income taxes, (vii) fair value of assets acquired and liabilities assumed in an acquisition and (viii) fair values of derivatives, deferred premiums and performance unit awards. As fair value is a market-based measurement, it is determined based on the assumptions that would be used by market participants. These estimates and assumptions are based on management's best judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment. Such estimates and assumptions are adjusted when facts and circumstances dictate. Illiquid credit markets and volatile equity and energy markets have combined to increase the uncertainty inherent in such estimates and assumptions. Management believes its estimates and assumptions to be reasonable under the circumstances. As future events and their effects cannot be determined with precision, actual values and results could differ from these estimates. Any changes in estimates resulting from future changes in the economic environment will be reflected in the financial statements in future periods.

Reclassifications

Reclassifications

Certain amounts in the accompanying unaudited consolidated financial statements have been reclassified to conform to the 2016 presentation. These reclassifications had no impact to previously reported net loss, stockholders' equity or cash flows.

Accounts receivable

Accounts receivable

The Company sells produced oil, NGL and natural gas and purchased oil to various customers and participates with other parties in the development and operation of oil and natural gas properties. The Company's accounts receivable are generally unsecured. Accounts receivable for joint interest billings are recorded as amounts billed to customers less an allowance for doubtful accounts.

Joint interest operations amounts are considered past due after 30 days. The Company determines joint interest operations accounts receivable allowances based on management's assessment of the creditworthiness of the joint interest owners. Additionally, as the operator of the majority of its wells, the Company has the ability to realize some or all of the receivables through netting of anticipated future production revenues. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses, current receivables aging and existing industry and economic data. The Company reviews its allowance for doubtful accounts quarterly. Past due amounts greater than 90 days and over a specified amount are reviewed individually for collectability. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is remote.

Derivatives

Derivatives

The Company uses derivatives to reduce exposure to fluctuations in the prices of oil, NGL and natural gas. By removing a significant portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flows from operations due to fluctuations in commodity prices. These transactions are in the form of puts, swaps, collars and, in prior periods, basis swaps.

Derivatives are recorded at fair value and are presented on a net basis on the unaudited consolidated balance sheets as assets or liabilities. The Company nets the fair value of derivatives by counterparty where the right of offset exists. The Company determines the fair value of its derivatives by utilizing pricing models for substantially similar instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. See Note 9 for discussion regarding the fair value of the Company's derivatives. 

The Company's derivatives were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the unaudited consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities. See Notes 8 and 9 for discussion regarding the Company's derivatives.

Full cost method of accounting

The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain related employee costs, incurred for the purpose of finding oil, NGL and natural gas are capitalized and depleted on a composite unit of production method based on proved oil, NGL and natural gas reserves. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Costs, including related employee costs, associated with production and general corporate activities are expensed in the period incurred. Sales of oil and natural gas 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 Company excludes the costs directly associated with acquisition and evaluation of unevaluated properties from the depletion calculation until it is determined whether or not proved reserves can be assigned to the properties. The Company capitalizes a portion of its interest costs on its unevaluated properties. Capitalized interest becomes a part of the cost of the unevaluated properties and is subject to depletion when proved reserves can be assigned to the associated properties. All items classified as unevaluated property are assessed on a quarterly basis for possible impairment or reduction in value. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of evaluated reserves and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion.

The full cost ceiling is based principally on the estimated future net revenues from proved oil and natural gas properties discounted at 10%.

Debt issuance costs

Debt issuance costs

Debt issuance fees, which are recorded at cost, net of amortization, are amortized over the life of the respective debt agreements utilizing the effective interest and straight-line methods.

Asset retirement obligations

 Asset retirement obligations

Asset retirement obligations associated with the retirement of tangible long-lived assets are recognized as a liability in the period in which they are incurred and become determinable. The associated asset retirement costs are part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related long-lived asset is charged to expense through depletion, or for midstream service asset retirement cost through depreciation, of the associated asset. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and as corresponding accretion expense.

The fair value of additions to the asset retirement obligation liability is measured using valuation techniques consistent with the income approach, which converts future cash flows into a single discounted amount. Significant inputs to the valuation include: (i) estimated plug and abandonment cost per well based on Company experience, (ii) estimated remaining life per well, (iii) estimated removal and/or remediation costs for midstream service assets, (iv) estimated remaining life of midstream service assets, (v) future inflation factors and (vi) the Company's average credit adjusted risk-free rate. Inherent in the fair value calculation of asset retirement obligations are numerous assumptions and judgments including, in addition to those noted above, the ultimate settlement of these amounts, the ultimate timing of such settlement and changes in legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing asset retirement obligation liability, a corresponding adjustment will be made to the asset balance.

The Company is obligated by contractual and regulatory requirements to remove certain pipeline assets and perform other remediation of the sites where such pipeline assets are located upon the retirement of those assets. However, the fair value of the asset retirement obligation cannot currently be reasonably estimated because the settlement dates are indeterminate. The Company will record an asset retirement obligation for pipeline assets in the periods in which settlement dates become reasonably determinable.

Fair value measurements

Fair value measurements

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

Fair value measurements

The Company accounts for its oil and natural gas derivatives at fair value. The fair value of derivatives is determined utilizing pricing models for similar instruments. The models use a variety of techniques to arrive at fair value, including quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward curves generated from a compilation of data gathered from third parties.

The Company has categorized its assets and liabilities measured at fair value, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).

Assets and liabilities recorded at fair value on the unaudited consolidated balance sheets are categorized based on inputs to the valuation techniques as follows: 

Level 1—	Assets and liabilities recorded at fair value for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access. Active markets are considered to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2—	Assets and liabilities recorded at fair value for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the assets or liabilities. Substantially all of these inputs are observable in the marketplace throughout the full term of the price risk management instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace.
Level 3—	Assets and liabilities recorded at fair value for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. Unobservable inputs are not corroborated by market data. These inputs reflect management's own assumptions about the assumptions a market participant would use in pricing the asset or liability.

When the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety. The Company conducts a review of fair value hierarchy classifications on an annual basis. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities. Transfers between fair value hierarchy levels are recognized and reported in the period in which the transfer occurred.

The Company accounts for the impairment of long-lived assets and inventory, if any, at fair value on a nonrecurring basis. For purposes of fair value measurement, it was determined that the impairment of long-lived assets and inventory are classified as Level 3, based on the use of internally developed cash flow models.

Treasury stock

Treasury stock

Laredo's employees may elect to have the Company withhold shares of stock to satisfy their tax withholding obligations that arise upon the lapse of restrictions on their stock awards. Such treasury stock is recorded at cost and retired upon acquisition.

Compensation awards

Compensation awards

Stock-based compensation expense, net of amounts capitalized, is included in "General and administrative" in the unaudited consolidated statements of operations over the awards' vesting periods and is based on the awards' grant date fair value. The Company utilizes the closing stock price on the grant date, less an expected forfeiture rate, to determine the fair value of service vesting restricted stock awards and a Black-Scholes pricing model to determine the fair values of service vesting restricted stock option awards. The Company utilizes a Monte Carlo simulation prepared by an independent third party to determine the fair values of the performance share awards and, in prior periods, the performance unit awards. The Company capitalizes a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration and development of its oil and gas properties into the full cost pool. Capitalized stock-based compensation is included as an addition to "Oil and natural gas properties" in the unaudited consolidated balance sheets.

The Company recognizes the fair value of stock-based compensation awards expected to vest over the requisite service period as a charge against earnings, net of amounts capitalized. The Company's stock-based compensation awards are accounted for as equity instruments, and in prior periods, its performance unit awards were accounted for as liability awards. Stock-based compensation is included in "General and administrative" in the unaudited consolidated statements of operations. The Company capitalizes a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration and development of oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included as an addition to "Oil and natural gas properties" in the unaudited consolidated balance sheets.

Environmental

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.

Long-lived assets

Impairment losses are recorded on property and equipment used in operations and other long-lived assets when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets' carrying amount. Impairment is measured based on the excess of the carrying amount over the fair value of the asset.

Materials and supplies and line-fill

Materials and supplies inventory used in developing oil and natural gas properties and midstream service assets are carried at the lower of cost or market ("LCM") with cost determined using the weighted-average cost method and are included in "Other current assets" and "Other assets, net" on the unaudited consolidated balance sheets. The market price for materials and supplies is determined utilizing a replacement cost approach (Level 2).

Beginning at March 31, 2016, frac pit water inventory used in developing oil and natural gas properties is carried at LCM with cost determined using the weighted-average cost method and is included in "Other current assets" on the unaudited consolidated balance sheets. The market price for frac pit water inventory is determined utilizing a replacement cost approach.

The minimum volume of product in a pipeline system that enables the system to operate is known as line-fill and is generally not available to be withdrawn from the pipeline system until the expiration of the transportation contract. The Company owns oil line-fill in third-party pipelines, which is accounted for at LCM with cost determined using the weighted-average cost method and is included in "Other assets, net" on the unaudited consolidated balance sheets. The LCM adjustment is determined utilizing a quoted market price adjusted for regional price differentials (Level 2).

Income taxes

The impact of significant discrete items is separately recognized in the quarter in which the discrete items occur. The vesting of certain restricted stock awards could result in federal and state income tax expense or benefits related to the difference between the market price of the common stock at the date of vesting and the grant date. The exercise of stock option awards could result in federal and state income tax expense or benefits related to the difference between the fair value of the stock option at the grant date and the intrinsic value of the stock option when exercised. The tax impact resulting from vestings of restricted stock awards and exercise of option awards are discrete items.

Income taxes

Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating losses and tax credit carry-forwards. Under this method, deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income (loss) in the period that includes the enactment date.

The Company evaluates uncertain tax positions for recognition and measurement in the unaudited consolidated financial statements. To recognize a tax position, the Company determines whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more-likely-than-not threshold is measured to determine the amount of benefit to be recognized in the unaudited consolidated financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement.

Credit risk

Credit risk

The Company's oil, NGL and natural gas sales are made to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. The Company's joint operations accounts receivable are from a number of oil and natural gas companies, partnerships, individuals and others who own interests in the oil and natural gas properties operated by the Company. The Company's sales of purchased oil are made to one customer. Management believes that any credit risk imposed by a concentration in the oil and natural gas industry is offset by the creditworthiness of the Company's customer base and industry partners. The Company routinely assesses the recoverability of all material trade and other receivables to determine collectability.

The Company uses derivatives to hedge its exposure to oil and natural gas price volatility. These transactions expose the Company to potential credit risk from its counterparties. In accordance with the Company's standard practice, its derivatives are subject to counterparty netting under agreements governing such derivatives; therefore, the credit risk associated with its derivative counterparties is somewhat mitigated.

Net loss per share

Net loss per share

Basic net loss per share is computed by dividing net loss by the weighted-average number of common shares outstanding for the period. Diluted net loss per share reflects the potential dilution of non-vested restricted stock awards, performance share awards and outstanding restricted stock options.

Variable interest entity

Variable interest entity

An entity is referred to as a VIE pursuant to accounting guidance for consolidation if it possesses one of the following criteria: (i) it is thinly capitalized, (ii) the residual equity holders do not control the entity, (iii) the equity holders are shielded from the economic losses, (iv) the equity holders do not participate fully in the entity's residual economics, or (v) the entity was established with non-substantive voting interests. In order to determine if a VIE should be consolidated, an entity must determine if it is the primary beneficiary of the VIE. The primary beneficiary of a VIE is that variable interest-holder possessing a controlling financial interest through: (i) its power to direct the activities of the VIE that most significantly impact the VIE's economic performance and (ii) its obligation to absorb losses or its right to receive benefits from the VIE that could potentially be significant to the VIE. In order to determine whether the Company owns a variable interest in a VIE, a qualitative analysis is performed of the entity's design, organizational structure, primary decision makers and relevant agreements. The Company continually monitors its VIE exposure to determine if any events have occurred that could cause the primary beneficiary to change.

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Basis of presentation and significant accounting policies (Tables)

6 Months Ended

Jun. 30, 2016

Accounting Policies [Abstract]

Schedule of components of accounts receivable

Accounts receivable consisted of the following components for the periods presented:

(in thousands)	June 30, 2016		December 31, 2015
Oil, NGL and natural gas sales	$	42,629	$	25,582
Joint operations, net(1)	18,425		21,375
Sales of purchased oil and other products	15,000		11,775
Matured derivatives	12,223		27,469
Other	266		1,498
Total	$	88,543	$	87,699

______________________________________________________________________________

(1) Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.2 million as of both June 30, 2016 and December 31, 2015.

Schedule of property and equipment

The following table sets forth the Company's property and equipment as of the periods presented:

(in thousands)	June 30, 2016			December 31, 2015
Evaluated oil and natural gas properties	$	5,309,151		$	5,103,635
Less accumulated depletion and impairment	(4,448,482		)	(4,218,942		)
Evaluated oil and natural gas properties, net	860,669			884,693
Unevaluated properties not being depleted	114,507			140,299
Midstream service assets	148,227			147,811
Less accumulated depreciation	(20,175		)	(16,086		)
Midstream service assets, net	128,052			131,725
Depreciable other fixed assets	46,255			46,799
Less accumulated depreciation and amortization	(20,218		)	(18,169		)
Depreciable other fixed assets, net	26,037			28,630
Land	14,914			14,908
Total property and equipment, net	$	1,144,179		$	1,200,255

Benchmark Prices, Realized Prices and the corresponding non-cash full cost ceiling impairments

The following table presents the Benchmark Prices, Realized Prices and the corresponding non-cash full cost ceiling impairments recorded as of the periods presented:

	For the quarters ended
	June 30, 2016		March 31, 2016		December 31, 2015		September 30, 2015		June 30, 2015
Benchmark Prices
Oil ($/Bbl)	$	39.63	$	42.77	$	46.79	$	55.73	$	68.17
NGL ($/Bbl)	$	17.08	$	17.51	$	18.75	$	21.87	$	26.73
Natural gas ($/MMBtu)	$	2.17	$	2.31	$	2.47	$	2.89	$	3.22
Realized Prices
Oil ($/Bbl)	$	37.96	$	41.33	$	45.58	$	54.28	$	66.68
NGL ($/Bbl)	$	10.80	$	11.25	$	12.50	$	15.25	$	19.56
Natural gas ($/Mcf)	$	1.64	$	1.75	$	1.89	$	2.30	$	2.62
Non-cash full cost ceiling impairment (in thousands)	$	—	$	161,064	$	975,011	$	906,420	$	488,046

Impairments

The following table presents inventory impairments recorded as of the periods presented:

	Three months ended June 30,				Six months ended June 30,
(in thousands)	2016		2015		2016		2015
Inventory impairments:
Materials and supplies(1)	$	963	$	1,553	$	963	$	2,320
Line-fill(2)	—		—		—		111
Total inventory impairments	$	963	$	1,553	$	963	$	2,431

______________________________________________________________________________

(1) Included in "Impairment expense" in the unaudited consolidated statements of operations and in "Impairment expense" for the Company's exploration and production segment presented in Note 16.

(2) Included in "Impairment expense" in the unaudited consolidated statements of operations and in "Impairment expense" for the Company's midstream and marketing segment presented in Note 16.

Schedule of future amortization expense of deferred debt issuance costs

Future amortization expense of debt issuance costs as of the period presented is as follows:

(in thousands)	June 30, 2016
Remaining 2016	$	2,092
2017	4,238
2018	4,068
2019	2,915
2020	3,005
Thereafter	4,585
Total	$	20,903

Schedule of other current assets

Other current assets consist of the following components for the periods presented:

(in thousands)	June 30, 2016		December 31, 2015
Inventory(1)	$	6,986	$	6,974
Prepaid expenses and other	7,459		7,600
Total other current assets	$	14,445	$	14,574

______________________________________________________________________________

(1) See Note 2.g for discussion of inventory held by the Company.

Schedule of other current liabilities

Other current liabilities consist of the following components for the periods presented:

(in thousands)	June 30, 2016		December 31, 2015
Accrued interest payable	$	24,161	$	24,208
Costs of purchased oil payable	15,629		12,189
Lease operating expense payable	11,570		13,205
Accrued compensation and benefits	8,720		14,342
Capital contribution payable to equity method investee(1)	—		27,583
Other accrued liabilities	12,440		14,695
Total other current liabilities	$	72,520	$	106,222

______________________________________________________________________________

(1) See Notes 14 and 15 for additional discussion regarding our equity method investee.

Schedule of reconciliation of asset retirement obligation liability

The following reconciles the Company's asset retirement obligation liability for the periods presented:

(in thousands)	Six months ended June 30, 2016			Year ended December 31, 2015
Liability at beginning of period	$	46,306		$	32,198
Liabilities added due to acquisitions, drilling, midstream service asset construction and other	253			2,236
Accretion expense	1,704			2,423
Liabilities settled upon plugging and abandonment	(526		)	(146		)
Liabilities removed due to sale of property	—			(2,005		)
Revision of estimates(1)	—			11,600
Liability at end of period	$	47,737		$	46,306

_____________________________________________________________________________

(1) The revision of estimates that occurred during the year ended December 31, 2015 is mainly related to a change in the estimated remaining life per well due to the decline in commodity prices.

Schedule of non-cash investing and supplemental cash flow information

The following presents the non-cash investing and supplemental cash flow information for the periods presented:

	Six months ended June 30,
(in thousands)	2016			2015
Non-cash investing information:
Change in accrued capital expenditures	$	(22,012	)	$	(53,209	)
Change in accrued capital contribution to equity method investee(1)	$	(27,583	)	$	27,917
Capitalized asset retirement cost	$	253		$	1,402
Supplemental cash flow information:
Capitalized interest	$	115		$	178

______________________________________________________________________________

(1) See Notes 14 and 15 for additional discussion regarding our equity method investee.

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Divestiture (Tables)

6 Months Ended

Jun. 30, 2016

Discontinued Operations and Disposal Groups [Abstract]

Schedule of revenues and expenses for discontinued operations

The following table presents revenues and expenses of the oil and natural gas properties sold included in the accompanying unaudited consolidated statements of operations for the periods presented:

(in thousands)	Three months ended June 30, 2015		Six months ended June 30, 2015
Oil, NGL and natural gas sales	$	1,970	$	4,048
Expenses(1)	2,098		4,710

_____________________________________________________________________________

(1) Expenses include (i) lease operating expense, (ii) production and ad valorem tax expense, (iii) accretion expense and (iv) depletion expense.

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Debt (Tables)

6 Months Ended

Jun. 30, 2016

Debt Disclosure [Abstract]

Schedule of carrying amount and fair value of debt instruments

The following table presents the carrying amount and fair values of the Company's debt for the periods presented:

	June 30, 2016				December 31, 2015
(in thousands)	Long-term debt		Fair value		Long-term debt		Fair value
January 2022 Notes	$	450,000	$	426,564	$	450,000	$	388,301
May 2022 Notes	500,000		501,250		500,000		460,000
March 2023 Notes	350,000		349,965		350,000		301,000
Senior Secured Credit Facility	110,318		110,261		135,000		134,993
Total value of debt	$	1,410,318	$	1,388,040	$	1,435,000	$	1,284,294

Schedule of debt

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

	June 30, 2016							December 31, 2015
(in thousands)	Long-term debt		Debt issuance costs, net			Long-term debt, net		Long-term debt		Debt issuance costs, net			Long-term debt, net
January 2022 Notes	$	450,000	$	(5,451	)	$	444,549	$	450,000	$	(5,939	)	$	444,061
May 2022 Notes	500,000		(6,624		)	493,376		500,000		(7,066		)	492,934
March 2023 Notes	350,000		(5,366		)	344,634		350,000		(5,769		)	344,231
Senior Secured Credit Facility(1)	110,318		—			110,318		135,000		—			135,000
Total	$	1,410,318	$	(17,441	)	$	1,392,877	$	1,435,000	$	(18,774	)	$	1,416,226

______________________________________________________________________________

(1) Debt issuance costs related to our Senior Secured Credit Facility are recorded in "Other assets, net" on the unaudited consolidated balance sheets.

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Employee compensation (Tables)

6 Months Ended

Jun. 30, 2016

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions

The assumptions used to estimate the fair value of the 22,324 restricted stock options granted on April 1, 2016 and the 994,022 restricted stock options granted on May 25, 2016 are as follows:

	April 1, 2016			May 25, 2016
Risk-free interest rate(1)	1.44		%	1.58		%
Expected option life(2)	6.25 years			6.25 years
Expected volatility(3)	61.34		%	61.94		%
Fair value per stock option	$	4.44		$	9.75

(1) United States Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, correlating the treasury yield terms to the expected life of the option.

(2) As the Company had limited exercise history at the time of valuation relating to terminations and modifications, expected option life assumptions were developed using the simplified method in accordance with GAAP.

(3) The Company utilized its own historical volatility in order to develop the expected volatility.     

Schedule Share-based Compensation, Performance Shares Award Unvested Activity

The following table reflects the performance share award activity for the six months ended June 30, 2016:

(in thousands, except for weighted-average grant date fair values)	Performance share awards		Weighted-average grant date fair value (per award)
Outstanding as of December 31, 2015	874		$	20.06
Granted	1,801		$	17.71
Forfeited	(247	)	$	19.69
Vested	—		$	—
Outstanding as of June 30, 2016	2,428		$	18.36

Schedule of stock option award activity

The following table reflects the stock option award activity for the six months ended June 30, 2016:

(in thousands, except for weighted-average price and contractual term)	Restricted stock option awards		Weighted-average  price (per option)		Weighted-average remaining contractual term (years)
Outstanding as of December 31, 2015	1,778		$	17.86	7.91
Granted	1,016		$	4.18
Exercised	(6	)	$	11.93
Expired or canceled	(35	)	$	22.40
Forfeited	(229	)	$	13.62
Outstanding as of June 30, 2016	2,524		$	12.69	8.06
Vested and exercisable at end of period(1)	916		$	19.49	6.41
Expected to vest at end of period(2)	1,600		$	8.75	9.02

_____________________________________________________________________________

(1) The vested and exercisable options as of June 30, 2016 had no aggregate intrinsic value.

(2) The restricted stock options expected to vest as of June 30, 2016 had $6.1 million aggregate intrinsic value.

Schedule of Nonvested Share Activity

The following table reflects the outstanding restricted stock awards for the six months ended June 30, 2016:

(in thousands, except for weighted-average grant date fair values)	Restricted stock awards		Weighted-average grant date fair value (per award)
Outstanding as of December 31, 2015	2,539		$	15.26
Granted	2,968		$	12.27
Forfeited	(221	)	$	15.16
Vested(1)	(1,124	)	$	16.06
Outstanding as of June 30, 2016	4,162		$	12.92

______________________________________________________________________________

(1) The vesting of certain restricted stock awards could result in federal and state income tax expense or benefit related to the difference between the market price of the common stock at the date of vesting and the date of grant. See Note 7 for additional discussion regarding the tax impact of vested stock awards.

Schedule Of Share Based Compensation Vesting Rights Options

In accordance with the LTIP and stock option agreement, the options granted will become exercisable in accordance with the following schedule based upon the number of full years of the optionee's continuous employment or service with the Company, following the date of grant:

Full years of continuous employment	Incremental percentage of option exercisable		Cumulative percentage of option exercisable
Less than one	—	%	—	%
One	25	%	25	%
Two	25	%	50	%
Three	25	%	75	%
Four	25	%	100	%

Schedule of stock-based compensation expense

The following has been recorded to stock-based compensation expense for the periods presented:

	Three months ended June 30,						Six months ended June 30,
(in thousands)	2016			2015			2016			2015
Restricted stock award compensation	$	4,692		$	4,520		$	8,460		$	7,458
Restricted stock option award compensation	777			1,279			1,401			1,949
Restricted performance share award compensation	1,593			1,378			1,821			2,273
Total stock-based compensation, gross	7,062			7,177			11,682			11,680
Less amounts capitalized in oil and natural gas properties	(989		)	(909		)	(1,771		)	(624		)
Total stock-based compensation, net of amounts capitalized	$	6,073		$	6,268		$	9,911		$	11,056

Performance Share Awards

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Schedule of Share-based Payment Award, Equity Instruments Other Than Options, Valuation Assumptions

The assumptions used to estimate the fair value of the 32,495 performance share awards granted on April 1, 2016 and the 1,768,297 performance share awards granted on May 25, 2016 are as follows:

	April 1, 2016			May 25, 2016
Risk-free rate(1)	0.87		%	1.02		%
Dividend yield	—		%	—		%
Expected volatility(2)	71.54		%	74.73		%
Laredo stock closing price on grant date	$	7.71		$	12.36
Fair value per performance share	$	9.83		$	17.86

______________________________________________________________________________

(1) The risk-free rate was derived using a term-matched zero-coupon yield derived from the Treasury Constant Maturities yield curve on the grant date.

(2) The Company utilized its own historical volatility over a lookback period equal to the length of the remaining performance period from the grant date in order to develop the expected volatility.

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Income taxes (Tables)

6 Months Ended

Jun. 30, 2016

Income Tax Disclosure [Abstract]

Schedule of income tax benefit

The Company is subject to federal and state income taxes and the Texas franchise tax. Income tax benefit for the periods presented consisted of the following:

	Three months ended June 30,				Six months ended June 30,
(in thousands)	2016		2015		2016		2015
Current taxes	$	—	$	—	$	—	$	—
Deferred taxes	—		221,846		—		218,203
Income tax benefit	$	—	$	221,846	$	—	$	218,203

Schedule of reconciliation of income tax expense computed by applying the federal income tax rate of 35% to pre-tax income from operations

Income tax benefit differed from amounts computed by applying the applicable federal income tax rate of 35% to pre-tax earnings as a result of the following:

	Three months ended June 30,						Six months ended June 30,
(in thousands)	2016			2015			2016			2015
Income tax benefit computed by applying the statutory rate	$	25,001		$	216,608		$	88,131		$	215,498
State income tax and change in valuation allowance	(541		)	5,776			187			5,867
Non-deductible stock-based compensation	—			(15		)	—			(106		)
Stock-based compensation tax deficiency	(190		)	(381		)	(4,012		)	(2,838		)
Increase in deferred tax valuation allowance	(24,323		)	(11		)	(84,218		)	(16		)
Other items	53			(131		)	(88		)	(202		)
Income tax benefit	$	—		$	221,846		$	—		$	218,203

Schedule of income tax deficiency from share-based compensation

The following table presents the tax impact of these shortfalls for the periods presented:

	Three months ended June 30,						Six months ended June 30,
(in thousands)	2016			2015			2016			2015
Vesting of restricted stock	$	(182	)	$	(388	)	$	(4,057	)	$	(2,889	)
Exercise of restricted stock options	(10		)	—			(10		)	—
Tax expense due to shortfalls	$	(192	)	$	(388	)	$	(4,067	)	$	(2,889	)

Schedule of significant components of deferred tax assets and liabilities

Significant components of the Company's net deferred tax asset for the periods presented are as follows:

(in thousands)	June 30, 2016			December 31, 2015
Oil and natural gas properties, midstream service assets and other fixed assets	$	282,612		$	306,997
Net operating loss carry-forward	528,625			479,022
Derivatives	(41,577		)	(98,675		)
Stock-based compensation	9,340			11,597
Equity method investee	(25,612		)	(31,711		)
Accrued bonus	2,544			4,763
Capitalized interest	2,173			2,525
Other	2,901			2,820
Net deferred tax asset before valuation allowance	761,006			677,338
Valuation allowance	(761,006		)	(677,338		)
Net deferred tax asset	$	—		$	—

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Derivatives (Tables)

6 Months Ended

Jun. 30, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments

During the six months ended June 30, 2016, the following derivatives were terminated:

	Aggregate volumes	Floor price		Contract period
Oil (volumes in Bbl):
Put portion of the associated collars	2,263,000	$	80.00	January 2017 - December 2017

During the six months ended June 30, 2016, the following derivatives were entered into:

	Aggregate volumes	Floor price		Ceiling price		Contract period
Oil (volumes in Bbl):
Put(1)	2,263,000	$	60.00	$	—	January 2017 - December 2017
Put(2)	2,098,750	$	60.00	$	—	January 2017 - December 2018
Put(3)	600,000	$	40.00	$	—	May 2016 - December 2016
Swap	1,095,000	$	52.12	$	—	January 2018 - December 2018
Natural gas (volumes in MMBtu):(4)
Put	8,040,000	$	2.50	$	—	January 2017 - December 2017
Put	8,220,000	$	2.50	$	—	January 2018 - December 2018
Collar	5,256,000	$	2.50	$	3.05	January 2017 - December 2017
Collar	4,635,500	$	2.50	$	3.60	January 2018 - December 2018

_____________________________________________________________________________

(1) As part of the Company's hedge restructuring, this put replaced the early terminated put portion of the restructured derivative contract collars. A premium of $40.0 million was paid at contract inception.

(2) As part of the Company's hedge restructuring, a premium of $40.0 million was paid at contract inception.

(3) There are $1.2 million in deferred premiums associated with this contract.

(4) There are $5.1 million in deferred premiums associated with these contracts.

Subsequent to June 30, 2016, the Company entered into the following new derivative contracts:

	Aggregate volumes	Price		Contract period
Oil (volumes in Bbl):(1)
Swap	1,003,750	$	51.90	January 2017 - December 2017
Swap	1,003,750	$	51.17	January 2017 - December 2017
NGL (volumes in Bbl):
Swap(2)	444,000	$	11.24	January 2017 - December 2017
Swap(3)	375,000	$	22.26	January 2017 - December 2017

_____________________________________________________________

(1) The associated derivatives will be settled based on the WTI NYMEX index oil price.

(2) The associated derivative will be settled based on the Mont Belvieu Purity Ethane-OPIS price.

(3) The associated derivative will be settled based on the Mont Belvieu Propane (TET)-OPIS price.

Schedule of gains and losses on derivative instruments

The following represents cash settlements received for derivatives, net for the periods presented:

	Three months ended June 30,				Six months ended June 30,
(in thousands)	2016		2015		2016		2015
Cash settlements received for matured derivatives, net	$	47,382	$	46,596	$	113,319	$	109,737
Cash settlements received for early terminations of derivatives, net(1)	—		—		80,000		—
Cash settlements received for derivatives, net	$	47,382	$	46,596	$	193,319	$	109,737

_____________________________________________________________________________

(1) The settlements amount for the six months ended June 30, 2016 includes $4.0 million in deferred premiums which were settled net with the early terminated contracts from which they derive.

Summary of open positions and derivatives in place

The following table summarizes open positions as of June 30, 2016, and represents, as of such date, derivatives in place through December 2018 on annual production volumes:

	Remaining year 2016		Year 2017		Year 2018
Oil positions:(1)
Puts:
Hedged volume (Bbl)	1,098,000		1,049,375		1,049,375
Weighted-average price ($/Bbl)	$	42.95	$	60.00	$	60.00
Swaps:
Hedged volume (Bbl)	791,200		—		1,095,000
Weighted-average price ($/Bbl)	$	84.82	$	—	$	52.12
Collars:
Hedged volume (Bbl)	1,833,500		2,628,000		—
Weighted-average floor price ($/Bbl)	$	73.98	$	60.00	$	—
Weighted-average ceiling price ($/Bbl)	$	89.62	$	97.22	$	—
Totals:
Total volume hedged with floor price (Bbl)	3,722,700		3,677,375		2,144,375
Weighted-average floor price ($/Bbl)	$	67.13	$	60.00	$	55.98
Total volume hedged with ceiling price (Bbl)	2,624,700		2,628,000		1,095,000
Weighted-average ceiling price ($/Bbl)	$	88.18	$	97.22	$	52.12
Natural gas positions:(2)
Puts:
Hedged volume (MMBtu)	—		8,040,000		8,220,000
Weighted-average price ($/MMBtu)	$	—	$	2.50	$	2.50
Collars:
Hedged volume (MMBtu)	9,384,000		10,731,000		4,635,500
Weighted-average floor price ($/MMBtu)	$	3.00	$	2.76	$	2.50
Weighted-average ceiling price ($/MMBtu)	$	5.60	$	3.53	$	3.60
Totals:
Total volume hedged with floor price (MMBtu)	9,384,000		18,771,000		12,855,500
Weighted-average floor price ($/MMBtu)	$	3.00	$	2.65	$	2.50
Total volume hedged with ceiling price (MMBtu)	9,384,000		10,731,000		4,635,500
Weighted-average ceiling price ($/MMBtu)	$	5.60	$	3.53	$	3.60

_______________________________________________________________________________

(1) Oil derivatives are settled based on the average of the daily settlement prices for the First Nearby Month of the WTI NYMEX Light Sweet Crude Oil Futures Contract for each NYMEX Trading Day during each month.

(2) Natural gas derivatives are settled based on the Inside FERC index price for West Texas Waha for the calculation period.

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Fair value measurements (Tables)

6 Months Ended

Jun. 30, 2016

Fair Value Disclosures [Abstract]

Schedule of fair value hierarchy for assets and liabilities measured at fair value on a recurring basis

The following tables summarize the Company's fair value hierarchy by commodity on a gross basis and the net presentation on the unaudited consolidated balance sheets for derivative assets and liabilities measured at fair value on a recurring basis as of the periods presented:

(in thousands)	Level 1		Level 2			Level 3			Total gross fair value			Amounts offset			Net fair value presented on the unaudited consolidated balance sheets
As of June 30, 2016:
Assets
Current:
Oil derivatives	$	—	$	93,057		$	—		$	93,057		$	(515	)	$	92,542
Natural gas derivatives	—		3,458			—			3,458			(1,165		)	2,293
Oil deferred premiums	—		—			—			—			(5,467		)	(5,467		)
Natural gas deferred premiums	—		—			—			—			(403		)	(403		)
Noncurrent:
Oil derivatives	$	—	$	33,181		$	—		$	33,181		$	—		$	33,181
Natural gas derivatives	—		2,724			—			2,724			(2,724		)	—
Oil deferred premiums	—		—			—			—			(501		)	(501		)
Natural gas deferred premiums	—		—			—			—			—			—
Liabilities
Current:
Oil derivatives	$	—	$	—		$	—		$	—		$	515		$	515
Natural gas derivatives	—		(739		)	—			(739		)	1,165			426
Oil deferred premiums	—		—			(6,784		)	(6,784		)	5,467			(1,317		)
Natural gas deferred premiums	—		—			(1,507		)	(1,507		)	403			(1,104		)
Noncurrent:
Oil derivatives	$	—	$	(1,820	)	$	—		$	(1,820	)	$	—		$	(1,820	)
Natural gas derivatives	—		(774		)	—			(774		)	2,724			1,950
Oil deferred premiums	—		—			(501		)	(501		)	501			—
Natural gas deferred premiums	—		—			(3,870		)	(3,870		)	—			(3,870		)
Net derivative position	$	—	$	129,087		$	(12,662	)	$	116,425		$	—		$	116,425

(in thousands)	Level 1		Level 2		Level 3			Total gross fair value			Amounts offset			Net fair value presented on the unaudited consolidated balance sheets
As of December 31, 2015:
Assets
Current:
Oil derivatives	$	—	$	194,940	$	—		$	194,940		$	—		$	194,940
Natural gas derivatives	—		13,166		—			13,166			—			13,166
Oil deferred premiums	—		—		—			—			(9,301		)	(9,301		)
Natural gas deferred premiums	—		—		—			—			—			—
Noncurrent:
Oil derivatives	$	—	$	80,302	$	—		$	80,302		$	—		$	80,302
Natural gas derivatives	—		2,459		—			2,459			—			2,459
Oil deferred premiums	—		—		—			—			(4,877		)	(4,877		)
Natural gas deferred premiums	—		—		—			—			(441		)	(441		)
Liabilities
Current:
Oil derivatives	$	—	$	—	$	—		$	—		$	—		$	—
Natural gas derivatives	—		—		—			—			—			—
Oil deferred premiums	—		—		(9,301		)	(9,301		)	9,301			—
Natural gas deferred premiums	—		—		—			—			—			—
Noncurrent:
Oil derivatives	$	—	$	—	$	—		$	—		$	—		$	—
Natural gas derivatives	—		—		—			—			—			—
Oil deferred premiums	—		—		(4,877		)	(4,877		)	4,877			—
Natural gas deferred premiums	—		—		(441		)	(441		)	441			—
Net derivative position	$	—	$	290,867	$	(14,619	)	$	276,248		$	—		$	276,248

Actual cash payments required for deferred premium contracts

The following table presents actual cash payments required for deferred premiums for the calendar years presented:

(in thousands)	June 30, 2016
Remaining 2016	$	5,407
2017	5,354
2018	2,100
Total	$	12,861

Summary of changes in assets (liability) classified as Level 3 measurements

A summary of the changes in assets classified as Level 3 measurements for the periods presented are as follows:

	Three months ended June 30,						Six months ended June 30,
(in thousands)	2016			2015			2016			2015
Balance of Level 3 at beginning of period	$	(13,054	)	$	(8,882	)	$	(14,619	)	$	(9,285	)
Change in net present value of deferred premiums for derivatives	(61		)	(45		)	(133		)	(88		)
Total purchases and settlements:
Purchases	(1,960		)	(4,409		)	(6,072		)	(5,384		)
Settlements(1)	2,413			1,249			8,162			2,670
Balance of Level 3 at end of period	$	(12,662	)	$	(12,087	)	$	(12,662	)	$	(12,087	)

_____________________________________________________________________________

(1) The amount for the six months ended June 30, 2016 includes $3.9 million which represents the present value of deferred premiums settled in the Company's restructuring upon their early termination.

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Net loss per share (Tables)

6 Months Ended

Jun. 30, 2016

Earnings Per Share [Abstract]

Schedule of calculation of basic and diluted weighted average shares outstanding and net income per share

The following is the calculation of basic and diluted weighted-average common shares outstanding and net loss per share for the periods presented:

	Three months ended June 30,						Six months ended June 30,
(in thousands, except for per share data)	2016			2015			2016			2015
Net loss (numerator):
Net loss—basic and diluted	$	(71,432	)	$	(397,034	)	$	(251,803	)	$	(397,506	)
Weighted-average common shares outstanding (denominator):
Basic	217,564			211,078			214,562			186,886
Diluted	217,564			211,078			214,562			186,886
Net loss per share:
Basic	$	(0.33	)	$	(1.88	)	$	(1.17	)	$	(2.13	)
Diluted	$	(0.33	)	$	(1.88	)	$	(1.17	)	$	(2.13	)

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Related Parties (Tables)

6 Months Ended

Jun. 30, 2016

Related Party Transactions [Abstract]

Schedule of Related Party Transactions

The following table summarizes items included in the unaudited consolidated statements of operations related to Medallion for the periods presented:

	Three months ended June 30,				Six months ended June 30,
(in thousands)	2016		2015		2016		2015
Midstream service revenues	$	—	$	390	$	—	$	487
Minimum volume commitments	—		3,579		—		5,235
Interest and other income	—		—		—		108

The following table summarizes items included in the unaudited consolidated balance sheets related to Medallion as of the dates presented:

(in thousands)	June 30, 2016		December 31, 2015
Accounts receivable, net	$	—	$	1,163
Other assets, net(1)	1,025		1,025
Other current liabilities(2)	102		27,583

______________________________________________________________________________

(1) Amounts included in "Other assets, net" above represent LMS owned line-fill in Medallion's pipeline.

(2) Amounts included in "Other current liabilities" above represent LMS' accrued line-fill purchase in Medallion's pipeline as of June 30, 2016 and capital contribution payable to Medallion as of December 31, 2015.

The following table summarizes the capitalized oil and natural gas properties related to H&P included in the unaudited consolidated statements of cash flows for the periods presented:

	Three months ended June 30,				Six months ended June 30,
(in thousands)	2016		2015		2016		2015
Capital expenditures:
Oil and natural gas properties	$	—	$	177	$	—	$	2,434

The following table summarizes the oil, NGL and natural gas sales and midstream service revenues received from Targa included in the unaudited consolidated statements of operations for the periods presented:

	Three months ended June 30,				Six months ended June 30,
(in thousands)	2016		2015		2016		2015
Oil, NGL and natural gas sales	$	18,112	$	34,012	$	35,917	$	53,643
Midstream service revenues	102		—		237		—

The following table summarizes the amounts included in accounts receivable, net from Targa in the unaudited consolidated balance sheets as of the dates presented:

(in thousands)	June 30, 2016		December 31, 2015
Accounts receivable, net	$	9,337	$	6,097

The following table summarizes the lease operating expenses related to Archrock included in the unaudited consolidated statements of operations for the periods presented:

	Three months ended June 30,				Six months ended June 30,
(in thousands)	2016		2015		2016		2015
Lease operating expenses	$	526	$	391	$	1,001	$	776

The following table summarizes the capital expenditures related to Archrock included in the unaudited consolidated statements of cash flows for the periods presented:

	Three months ended June 30,				Six months ended June 30,
(in thousands)	2016		2015		2016		2015
Capital expenditures:
Midstream service assets	$	—	$	18	$	20	$	64

The following table summarizes the amounts included in accounts payable from Archrock in the unaudited consolidated balance sheets as of the dates presented:

(in thousands)	June 30, 2016		December 31, 2015
Accounts payable	$	—	$	13

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Segments (Tables)

6 Months Ended

Jun. 30, 2016

Segment Reporting [Abstract]

Schedule of segment reporting information, by segment

The following table presents selected financial information, for the periods presented, regarding the Company's operating segments on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis:

(in thousands)	Exploration and production			Midstream and marketing			Eliminations			Consolidated company
Three months ended June 30, 2016:
Oil, NGL and natural gas sales	$	102,526		$	—		$	—		$	102,526
Midstream service revenues	—			11,138			(9,506		)	1,632
Sales of purchased oil	—			42,615			—			42,615
Total revenues	102,526			53,753			(9,506		)	146,773
Lease operating expenses, including production tax	29,793			—			(2,586		)	27,207
Midstream service expenses	—			6,572			(5,394		)	1,178
Costs of purchased oil	—			44,012			—			44,012
General and administrative(1)	18,818			1,684			—			20,502
Depletion, depreciation and amortization(2)	31,969			2,208			—			34,177
Impairment expense	963			—			—			963
Other operating costs and expenses(3)	806			54			—			860
Operating income (loss)	$	20,177		$	(777	)	$	(1,526	)	$	17,874
Other financial information:
Income from equity method investee	$	—		$	3,696		$	—		$	3,696
Interest expense(4)	$	(22,050	)	$	(1,462	)	$	—		$	(23,512	)
Capital expenditures	$	(92,089	)	$	(1,488	)	$	—		$	(93,577	)
Gross property and equipment(6)	$	5,484,416		$	366,858		$	(4,604	)	$	5,846,670
Three months ended June 30, 2015:
Oil, NGL and natural gas sales	$	125,679		$	221		$	(346	)	$	125,554
Midstream service revenues	—			4,362			(2,636		)	1,726
Sales of purchased oil	—			55,051			—			55,051
Total revenues	125,679			59,634			(2,982		)	182,331
Lease operating expenses, including production tax	41,423			—			(2,717		)	38,706
Midstream service expenses, including minimum volume commitments	4,399			998			(221		)	5,176
Costs of purchased oil	—			54,417			—			54,417
General and administrative(1)	21,347			1,861			—			23,208
Depletion, depreciation and amortization(2)	69,987			2,125			—			72,112
Impairment expense	489,599			—			—			489,599
Other operating costs and expenses(3)	548			45			—			593
Operating income (loss)	$	(501,624	)	$	188		$	(44	)	$	(501,480	)
Other financial information:
Income from equity method investee	$	—		$	2,914		$	—		$	2,914
Interest expense(4)	$	(22,845	)	$	(1,125	)	$	—		$	(23,970	)
Loss on early redemption of debt(5)	$	(30,056	)	$	(1,481	)	$	—		$	(31,537	)
Capital expenditures	$	(133,259	)	$	(13,841	)	$	—		$	(147,100	)
Gross property and equipment(6)	$	5,170,912		$	257,073		$	(365	)	$	5,427,620

_______________________________________________________________________________

(1) General and administrative expense was allocated based on the number of employees in the respective segment as of June 30, 2016 and 2015. Certain components of general and administrative expense, primarily payroll, deferred compensation and vehicle expenses, were not allocated but were actual expenses for each segment. Land and geology expenses were not allocated to the midstream and marketing segment.

(2) Depletion, depreciation and amortization were actual expenses for each segment with the exception of the allocation of depreciation of other fixed assets, which is based on the number of employees in the respective segment as of June 30, 2016 and 2015.

(3) Other operating costs and expenses consist of accretion of asset retirement obligations. These are actual costs and expenses and were not allocated.

(4) Interest expense was allocated to the exploration and production segment based on gross property and equipment as of June 30, 2016 and 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of June 30, 2016 and 2015.

(5) Loss on early redemption of debt was allocated to the exploration and production segment based on gross property and equipment as of June 30, 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of June 30, 2015.

(6) Gross property and equipment for the midstream and marketing segment includes investment in equity method investee totaling $213.6 million and $103.2 million as of June 30, 2016 and 2015, respectively. Other fixed assets were allocated based on the number of employees in the respective segment as of June 30, 2016 and 2015.

(in thousands)	Exploration and production			Midstream and marketing			Eliminations			Consolidated company
Six months ended June 30, 2016:
Oil, NGL and natural gas sales	$	175,668		$	—		$	—		$	175,668
Midstream service revenues	—			22,405			(18,972		)	3,433
Sales of purchased oil	—			74,229			—			74,229
Total revenues	175,668			96,634			(18,972		)	253,330
Lease operating expenses, including production tax	59,157			—			(4,997		)	54,160
Midstream service expenses	—			13,081			(11,294		)	1,787
Costs of purchased oil	—			76,958			—			76,958
General and administrative(1)	36,497			3,456			—			39,953
Depletion, depreciation and amortization(2)	71,261			4,394			—			75,655
Impairment expense	162,027			—			—			162,027
Other operating costs and expenses(3)	1,598			106			—			1,704
Operating loss	$	(154,872	)	$	(1,361	)	$	(2,681	)	$	(158,914	)
Other financial information:
Income from equity method investee	$	—		$	5,994		$	—		$	5,994
Interest expense(4)	$	(44,353	)	$	(2,864	)	$	—		$	(47,217	)
Capital expenditures	$	(197,874	)	$	(3,425	)	$	—		$	(201,299	)
Gross property and equipment(6)	$	5,484,416		$	366,858		$	(4,604	)	$	5,846,670
Six months ended June 30, 2015:
Oil, NGL and natural gas sales	$	243,890		$	333		$	(551	)	$	243,672
Midstream service revenues	—			8,045			(5,010		)	3,035
Sales of purchased oil	—			86,318			—			86,318
Total revenues	243,890			94,696			(5,561		)	333,025
Lease operating expenses, including production tax	85,268			—			(5,096		)	80,172
Midstream service expenses, including minimum volume commitments	4,399			4,340			(333		)	8,406
Costs of purchased oil	—			85,617			—			85,617
General and administrative(1)	41,125			3,938			—			45,063
Depletion, depreciation and amortization(2)	140,244			3,810			—			144,054
Impairment expense	490,366			111			—			490,477
Other operating costs and expenses(3)	6,972			242			—			7,214
Operating loss	$	(524,484	)	$	(3,362	)	$	(132	)	$	(527,978	)
Other financial information:
Income from equity method investee	$	—		$	2,481		$	—		$	2,481
Interest expense(4)	$	(53,932	)	$	(2,452	)	$	—		$	(56,384	)
Loss on early redemption of debt(5)	$	(30,056	)	$	(1,481	)	$	—		$	(31,537	)
Capital expenditures	$	(380,872	)	$	(34,314	)	$	—		$	(415,186	)
Gross property and equipment(6)	$	5,170,912		$	257,073		$	(365	)	$	5,427,620

_______________________________________________________________________________

(1) General and administrative expense was allocated based on the number of employees in the respective segment as of June 30, 2016 and 2015. Certain components of general and administrative expense, primarily payroll, deferred compensation and vehicle expenses, were not allocated but were actual expenses for each segment. Land and geology expenses were not allocated to the midstream and marketing segment.

(2) Depletion, depreciation and amortization were actual expenses for each segment with the exception of the allocation of depreciation of other fixed assets, which is based on the number of employees in the respective segment as of June 30, 2016 and 2015.

(3) Other operating costs and expenses consist of accretion of asset retirement obligations for the six months ended June 30, 2016 and 2015 and restructuring expense for the six months ended June 30, 2015. These are actual costs and expenses and were not allocated.

(4) Interest expense was allocated to the exploration and production segment based on gross property and equipment as of June 30, 2016 and 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of June 30, 2016 and 2015.

(5) Loss on early redemption of debt was allocated to the exploration and production segment based on gross property and equipment as of June 30, 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of June 30, 2015.

(6) Gross property and equipment for the midstream and marketing segment includes investment in equity method investee totaling $213.6 million and $103.2 million as of June 30, 2016 and 2015, respectively. Other fixed assets were allocated based on the number of employees in the respective segment as of June 30, 2016 and 2015.

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Subsidiary guarantors (Tables)

6 Months Ended

Jun. 30, 2016

Condensed Financial Information of Parent Company Only Disclosure [Abstract]

Schedule of condensed consolidating balance sheet

Condensed consolidating balance sheet

June 30, 2016

(Unaudited)

(in thousands)	Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Accounts receivable, net	$	73,429	$	15,114	$	—		$	88,543
Other current assets	120,982		1,737		—			122,719
Total oil and natural gas properties, net	970,445		9,335		(4,604		)	975,176
Total midstream service assets, net	—		128,052		—			128,052
Total other fixed assets, net	40,701		250		—			40,951
Investment in subsidiaries and equity method investee	348,623		213,616		(348,623		)	213,616
Total other long-term assets	37,526		3,568		—			41,094
Total assets	$	1,591,706	$	371,672	$	(353,227	)	$	1,610,151
Accounts payable	$	12,934	$	1,566	$	—		$	14,500
Other current liabilities	120,756		18,556		—			139,312
Long-term debt, net	1,392,877		—		—			1,392,877
Other long-term liabilities	51,373		2,927		—			54,300
Stockholders' equity	13,766		348,623		(353,227		)	9,162
Total liabilities and stockholders' equity	$	1,591,706	$	371,672	$	(353,227	)	$	1,610,151

Condensed consolidating balance sheet

December 31, 2015

(Unaudited)

(in thousands)	Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Accounts receivable, net	$	74,613	$	13,086	$	—		$	87,699
Other current assets	244,477		56		—			244,533
Total oil and natural gas properties, net	1,017,565		9,350		(1,923		)	1,024,992
Total midstream service assets, net	—		131,725		—			131,725
Total other fixed assets, net	43,210		328		—			43,538
Investment in subsidiaries and equity method investee	301,891		192,524		(301,891		)	192,524
Total other long-term assets	84,360		3,916		—			88,276
Total assets	$	1,766,116	$	350,985	$	(303,814	)	$	1,813,287
Accounts payable	$	12,203	$	1,978	$	—		$	14,181
Other current liabilities	158,283		44,351		—			202,634
Long-term debt, net	1,416,226		—		—			1,416,226
Other long-term liabilities	46,034		2,765		—			48,799
Stockholders' equity	133,370		301,891		(303,814		)	131,447
Total liabilities and stockholders' equity	$	1,766,116	$	350,985	$	(303,814	)	$	1,813,287

Schedule of condensed consolidating statement of operations

Condensed consolidating statement of operations

For the three months ended June 30, 2016

(Unaudited)

(in thousands)	Laredo			Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Total revenues	$	102,511		$	53,768	$	(9,506	)	$	146,773
Total costs and expenses	84,137			52,742		(7,980		)	128,899
Operating income	18,374			1,026		(1,526		)	17,874
Interest expense and other, net	(23,501		)	—		—			(23,501		)
Other non-operating income (expense)	(64,779		)	3,692		(4,718		)	(65,805		)
Income (loss) before income tax	(69,906		)	4,718		(6,244		)	(71,432		)
Income tax	—			—		—			—
Net income (loss)	$	(69,906	)	$	4,718	$	(6,244	)	$	(71,432	)

Condensed consolidating statement of operations

For the six months ended June 30, 2016

(Unaudited)

(in thousands)	Laredo			Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Total revenues	$	175,633		$	96,669	$	(18,972	)	$	253,330
Total costs and expenses	334,201			94,334		(16,291		)	412,244
Operating income (loss)	(158,568		)	2,335		(2,681		)	(158,914		)
Interest expense and other, net	(47,107		)	—		—			(47,107		)
Other non-operating income (expense)	(43,447		)	5,983		(8,318		)	(45,782		)
Income (loss) before income tax	(249,122		)	8,318		(10,999		)	(251,803		)
Income tax	—			—		—			—
Net income (loss)	$	(249,122	)	$	8,318	$	(10,999	)	$	(251,803	)

Condensed consolidating statement of operations

For the three months ended June 30, 2015

(Unaudited)

(in thousands)	Laredo			Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Total revenues	$	125,687		$	59,626	$	(2,982	)	$	182,331
Total costs and expenses	629,359			57,390		(2,938		)	683,811
Operating income (loss)	(503,672		)	2,236		(44		)	(501,480		)
Interest expense and other, net	(23,797		)	—		—			(23,797		)
Other non-operating income (expense)	(91,367		)	2,914		(5,150		)	(93,603		)
Income (loss) before income tax	(618,836		)	5,150		(5,194		)	(618,880		)
Deferred income tax benefit	221,846			—		—			221,846
Net income (loss)	$	(396,990	)	$	5,150	$	(5,194	)	$	(397,034	)

Condensed consolidating statement of operations

For the six months ended June 30, 2015

(Unaudited)

(in thousands)	Laredo			Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Total revenues	$	243,833		$	94,753	$	(5,561	)	$	333,025
Total costs and expenses	772,667			93,765		(5,429		)	861,003
Operating income (loss)	(528,834		)	988		(132		)	(527,978		)
Interest expense and other, net	(56,088		)	—		—			(56,088		)
Other non-operating income (expense)	(30,655		)	2,481		(3,469		)	(31,643		)
Income (loss) before income tax	(615,577		)	3,469		(3,601		)	(615,709		)
Deferred income tax benefit	218,203			—		—			218,203
Net income (loss)	$	(397,374	)	$	3,469	$	(3,601	)	$	(397,506	)

Schedule of condensed consolidating statement of cash flows

Condensed consolidating statement of cash flows

For the six months ended June 30, 2016

(Unaudited)

(in thousands)	Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Net cash flows provided by operating activities	$	139,610		$	7,339		$	(8,318	)	$	138,631
Change in investment between affiliates	(47,069		)	38,751			8,318			—
Capital expenditures and other	(197,540		)	(46,090		)	—			(243,630		)
Net cash flows provided by financing activities	93,154			—			—			93,154
Net decrease in cash and cash equivalents	(11,845		)	—			—			(11,845		)
Cash and cash equivalents at beginning of period	31,153			1			—			31,154
Cash and cash equivalents at end of period	$	19,308		$	1		$	—		$	19,309

Condensed consolidating statement of cash flows

For the six months ended June 30, 2015

(Unaudited)

(in thousands)	Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Net cash flows provided by (used in) operating activities	$	136,092		$	(18,318	)	$	(3,469	)	$	114,305
Change in investment between affiliates	(70,472		)	67,003			3,469			—
Capital expenditures and other	(380,961		)	(48,685		)	—			(429,646		)
Net cash flows provided by financing activities	343,613			—			—			343,613
Net increase in cash and cash equivalents	28,272			—			—			28,272
Cash and cash equivalents at beginning of period	29,320			1			—			29,321
Cash and cash equivalents at end of period	$	57,592		$	1		$	—		$	57,593

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Subsequent Event (Tables)

6 Months Ended

Jun. 30, 2016

Subsequent Events [Abstract]

Schedule of Derivative Instruments

During the six months ended June 30, 2016, the following derivatives were terminated:

	Aggregate volumes	Floor price		Contract period
Oil (volumes in Bbl):
Put portion of the associated collars	2,263,000	$	80.00	January 2017 - December 2017

During the six months ended June 30, 2016, the following derivatives were entered into:

	Aggregate volumes	Floor price		Ceiling price		Contract period
Oil (volumes in Bbl):
Put(1)	2,263,000	$	60.00	$	—	January 2017 - December 2017
Put(2)	2,098,750	$	60.00	$	—	January 2017 - December 2018
Put(3)	600,000	$	40.00	$	—	May 2016 - December 2016
Swap	1,095,000	$	52.12	$	—	January 2018 - December 2018
Natural gas (volumes in MMBtu):(4)
Put	8,040,000	$	2.50	$	—	January 2017 - December 2017
Put	8,220,000	$	2.50	$	—	January 2018 - December 2018
Collar	5,256,000	$	2.50	$	3.05	January 2017 - December 2017
Collar	4,635,500	$	2.50	$	3.60	January 2018 - December 2018

_____________________________________________________________________________

(1) As part of the Company's hedge restructuring, this put replaced the early terminated put portion of the restructured derivative contract collars. A premium of $40.0 million was paid at contract inception.

(2) As part of the Company's hedge restructuring, a premium of $40.0 million was paid at contract inception.

(3) There are $1.2 million in deferred premiums associated with this contract.

(4) There are $5.1 million in deferred premiums associated with these contracts.

Subsequent to June 30, 2016, the Company entered into the following new derivative contracts:

	Aggregate volumes	Price		Contract period
Oil (volumes in Bbl):(1)
Swap	1,003,750	$	51.90	January 2017 - December 2017
Swap	1,003,750	$	51.17	January 2017 - December 2017
NGL (volumes in Bbl):
Swap(2)	444,000	$	11.24	January 2017 - December 2017
Swap(3)	375,000	$	22.26	January 2017 - December 2017

_____________________________________________________________

(1) The associated derivatives will be settled based on the WTI NYMEX index oil price.

(2) The associated derivative will be settled based on the Mont Belvieu Purity Ethane-OPIS price.

(3) The associated derivative will be settled based on the Mont Belvieu Propane (TET)-OPIS price.

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Supplementary information (Tables)

6 Months Ended

Jun. 30, 2016

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Schedule of costs incurred in the development of oil and natural gas properties

Costs incurred in the acquisition, exploration and development of oil, NGL and natural gas assets are presented below:

	Three months ended June 30,				Six months ended June 30,
(in thousands)	2016		2015		2016		2015
Property acquisition costs:							—
Evaluated	$	—	$	—	$	—	$	—
Unevaluated	—		—		—		—
Exploration	19,769		3,841		27,032		8,354
Development costs(1)	70,806		110,518		152,692		317,190
Total costs incurred	$	90,575	$	114,359	$	179,724	$	325,544

____________________________________________________________________________

(1) The costs incurred for oil, NGL and natural gas development activities include$0.1 million and $0.5 millionin asset retirement obligations for thethree months ended June 30, 2016 and 2015, respectively, and $0.2 million and $1.0 million for the six months ended June 30, 2016 and 2015, respectively.

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Organization (Details)	6 Months Ended
	Jun. 30, 2016 segment
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of operating segments	2

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Basis of presentation and significant accounting policies - Accounts receivable (Details) - USD ($) $ in Thousands		6 Months Ended
		Jun. 30, 2016	Dec. 31, 2015
Accounts receivable
Term of accounts receivable to be considered as past due (in days)		30 days
Term of past due balances to be reviewed individually for collectability (in days)		90 days
Oil, NGL and natural gas sales		$ 42,629	$ 25,582
Joint operations, net	[1]	18,425	21,375
Sales of purchased oil and other products		15,000	11,775
Matured derivatives		12,223	27,469
Other		266	1,498
Total		88,543	87,699
Allowance for doubtful accounts of accounts receivable for joint operations		$ (200)	$ (200)

[1] Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.2 million as of both June 30, 2016 and December 31, 2015.

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Basis of presentation and significant accounting policies - Property and equipment (Details) $ in Thousands						3 Months Ended					6 Months Ended
	Jun. 30, 2016 USD ($) $ / bbl $ / MMBTU	Mar. 31, 2016 $ / bbl $ / MMBTU	Dec. 31, 2015 USD ($) $ / bbl $ / MMBTU	Sep. 30, 2015 $ / bbl $ / MMBTU	Jun. 30, 2015 $ / bbl $ / MMBTU	Jun. 30, 2016 USD ($) $ / Boe	Mar. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Sep. 30, 2015 USD ($)	Jun. 30, 2015 USD ($) $ / Boe	Jun. 30, 2016 USD ($) $ / Boe	Jun. 30, 2015 $ / Boe
Property, Plant and Equipment, Net, by Type [Abstract]
Evaluated oil and natural gas properties	$ 5,309,151		$ 5,103,635			$ 5,309,151		$ 5,103,635			$ 5,309,151
Less accumulated depletion and impairment	(4,448,482)		(4,218,942)			(4,448,482)		(4,218,942)			(4,448,482)
Evaluated oil and natural gas properties, net	860,669		884,693			860,669		884,693			860,669
Unevaluated properties not being depleted	114,507		140,299			114,507		140,299			114,507
Total property and equipment, net	$ 1,144,179		$ 1,200,255			$ 1,144,179		1,200,255			$ 1,144,179
Depletion expense in dollars per BOE | $ / Boe						7.06				16.19	8.01	16.13
Discount rate full cost ceiling (percent)											10.00%
Non-cash full cost ceiling impairment (in thousands)						$ 0	$ 161,064	975,011	$ 906,420	$ 488,046
Crude Oil
Property, Plant and Equipment, Net, by Type [Abstract]
Benchmark Prices (in dollars per Bbl and MMBtu) | $ / bbl	39.63	42.77	46.79	55.73	68.17
Realized Prices (in dollars per Bbl and Mcf) | $ / bbl	37.96	41.33	45.58	54.28	66.68
Natural Gas Liquids
Property, Plant and Equipment, Net, by Type [Abstract]
Benchmark Prices (in dollars per Bbl and MMBtu) | $ / bbl	17.08	17.51	18.75	21.87	26.73
Realized Prices (in dollars per Bbl and Mcf) | $ / bbl	10.80	11.25	12.50	15.25	19.56
Natural Gas
Property, Plant and Equipment, Net, by Type [Abstract]
Benchmark Prices (in dollars per Bbl and MMBtu) | $ / MMBTU	2.17	2.31	2.47	2.89	3.22
Realized Prices (in dollars per Bbl and Mcf) | $ / MMBTU	1.64	1.75	1.89	2.30	2.62
Midstream Service Assets
Property, Plant and Equipment, Net, by Type [Abstract]
Midstream service assets	$ 148,227		$ 147,811			148,227		147,811			$ 148,227
Less accumulated depreciation and amortization	(20,175)		(16,086)			(20,175)		(16,086)			(20,175)
Total property and equipment, net	128,052		131,725			128,052		131,725			128,052
Other fixed assets
Property, Plant and Equipment, Net, by Type [Abstract]
Other fixed assets	46,255		46,799			46,255		46,799			46,255
Less accumulated depreciation and amortization	(20,218)		(18,169)			(20,218)		(18,169)			(20,218)
Total property and equipment, net	26,037		28,630			26,037		28,630			26,037
Land
Property, Plant and Equipment, Net, by Type [Abstract]
Other fixed assets	$ 14,914		$ 14,908			$ 14,914		$ 14,908			$ 14,914

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Basis of presentation and significant accounting policies - Long-lived assets and inventory (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment expense		$ 963	$ 489,599	$ 162,027	$ 490,477
Level 2 | Fair Value, Measurements, Nonrecurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment expense		963	1,553	963	2,431
Materials and Supplies | Level 2 | Fair Value, Measurements, Nonrecurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment expense	[1]	963	1,553	963	2,320
Line-fill | Level 2 | Fair Value, Measurements, Nonrecurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment expense	[2]	$ 0	$ 0	$ 0	$ 111

[1] Included in "Impairment expense" in the unaudited consolidated statements of operations and in "Impairment expense" for the Company's exploration and production segment presented in Note 16.

[2] Included in "Impairment expense" in the unaudited consolidated statements of operations and in "Impairment expense" for the Company's midstream and marketing segment presented in Note 16.

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Basis of presentation and significant accounting policies - Debt issuance costs (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Debt Instrument [Line Items]
Payments for debt issuance costs			$ 0	$ 6,759
Total debt issuance costs	$ (20,903)		(20,903)		$ (23,900)
Accumulated amortization	19,200		19,200		17,000
Write-off of debt issuance costs	842	$ 0	842	0
Remaining 2016	2,092		2,092
2017	4,238		4,238
2018	4,068		4,068
2019	2,915		2,915
2020	3,005		3,005
Thereafter	4,585		4,585
Total	$ (20,903)		$ (20,903)		$ (23,900)
Senior Notes | January 2019 Notes Issued January 2011
Debt Instrument [Line Items]
Write-off of debt issuance costs				$ 6,600

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Basis of presentation and significant accounting policies - Other current assets and liabilities (Details) - USD ($) $ in Thousands		Jun. 30, 2016	Dec. 31, 2015
Total other current assets
Inventory	[1]	$ 6,986	$ 6,974
Prepaid expenses and other		7,459	7,600
Total other current assets		14,445	14,574
Total other current liabilities
Accrued interest payable		24,161	24,208
Costs of purchased oil payable		15,629	12,189
Lease operating expense payable		11,570	13,205
Accrued compensation and benefits		8,720	14,342
Capital contribution payable to equity method investee	[2]	0	27,583
Other accrued liabilities		12,440	14,695
Total other current liabilities		$ 72,520	$ 106,222

[1] See Note 2.g for discussion of inventory held by the Company.

[2] (1)See Notes 14 and 15 for additional discussion regarding our equity method investee.

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Basis of presentation and significant accounting policies - Asset Retirement Obligations (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended		12 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liability at beginning of period				$ 46,306	$ 32,198	$ 32,198
Liabilities added due to acquisitions, drilling, midstream service asset construction and other				253		2,236
Accretion expense		$ 860	$ 593	1,704	$ 1,172	2,423
Liabilities settled upon plugging and abandonment				(526)		(146)
Liabilities removed due to sale of property				0		(2,005)
Revision of estimates	[1]			0		11,600
Liability at end of period		$ 47,737		$ 47,737		$ 46,306

[1] The revision of estimates that occurred during the year ended December 31, 2015 is mainly related to a change in the estimated remaining life per well due to the decline in commodity prices.

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Basis of presentation and significant accounting policies - Supplemental cash flow information (Details) - USD ($) $ in Thousands		6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015
Non-cash investing information:
Change in accrued capital expenditures		$ (22,012)	$ (53,209)
Change in accrued capital contribution to equity method investee	[1]	(27,583)	27,917
Capitalized asset retirement cost		253	1,402
Supplemental cash flow information:
Capitalized interest		$ 115	$ 178

[1] See Notes 14 and 15 for additional discussion regarding our equity method investee.

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Equity offerings (Details) - USD ($) $ in Thousands			6 Months Ended
	May 16, 2016	Mar. 05, 2015	Jun. 30, 2016	Jun. 30, 2015
Class of Stock [Line Items]
Proceeds from issuance of common stock, net of offering costs	$ 119,300	$ 754,200	$ 119,310	$ 754,163
Common Stock
Class of Stock [Line Items]
Equity issuance, net of offering costs (in shares)	10,925,000	69,000,000
Common Stock | Warburg Pincus LLC
Class of Stock [Line Items]
Equity issuance, net of offering costs (in shares)		29,800,000
Ownership percentage held by largest equity investor (percentage)		41.00%

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Divestitures (Details) - Non-strategic Assets $ in Thousands		3 Months Ended	6 Months Ended
		Jun. 30, 2015 USD ($)	Jun. 30, 2015 USD ($)	Sep. 15, 2015 USD ($) a property
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Oil, NGL and natural gas sales		$ 1,970	$ 4,048
Expenses	[1]	$ 2,098	$ 4,710
Disposal Group, Disposed of by Sale, Not Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Area of land (in acres) | a				6,060
Number of properties | property				123
Discontinued operation, sale price				$ 65,500
Discontinued operation, consideration				$ 64,800

[1] Expenses include (i) lease operating expense, (ii) production and ad valorem tax expense, (iii) accretion expense and (iv) depletion expense.

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Debt - Narrative (Details) - USD ($)			3 Months Ended			6 Months Ended
		Apr. 06, 2015	Jun. 30, 2016	Jun. 30, 2015	[1]	Jun. 30, 2016	Jun. 30, 2015	[2]	Dec. 31, 2015	Mar. 31, 2015	Mar. 18, 2015	Jan. 23, 2014	Apr. 27, 2012	Oct. 19, 2011	Jan. 20, 2011
Debt Instrument [Line Items]
Face amount of debt			$ 1,410,318,000			$ 1,410,318,000			$ 1,435,000,000
Loss on early redemption of debt			0	$ 31,537,000		0	$ 31,537,000
Senior Notes | March 2023 Notes
Debt Instrument [Line Items]
Interest rate (as a percent)											6.25%
Face amount of debt			350,000,000			350,000,000			350,000,000		$ 350,000,000.0
Senior Notes | January 2022 Notes
Debt Instrument [Line Items]
Interest rate (as a percent)												5.625%
Face amount of debt			450,000,000			450,000,000			450,000,000			$ 450,000,000.0
Senior Notes | May 2022 Notes
Debt Instrument [Line Items]
Interest rate (as a percent)													7.375%
Face amount of debt			500,000,000			500,000,000			500,000,000				$ 500,000,000
Senior Notes | January 2019 Notes Issued January 2011
Debt Instrument [Line Items]
Interest rate (as a percent)															9.50%
Face amount of debt															$ 350,000,000.0
Senior Notes | January 2019 Notes Issued October 2011
Debt Instrument [Line Items]
Interest rate (as a percent)														9.50%
Face amount of debt														$ 200,000,000.0
Senior Notes | January 2019 Notes
Debt Instrument [Line Items]
Repurchased face amount		$ 550,000,000.0
Debt instrument, redemption price percentage		104.75%
Loss on early redemption of debt		$ 31,500,000
Line of Credit | Senior Secured Credit Facility
Debt Instrument [Line Items]
Maximum borrowing capacity			2,000,000,000.0			2,000,000,000.0
Face amount of debt	[3]		110,318,000			110,318,000			$ 135,000,000
Current borrowing capacity			815,000,000			815,000,000
Outstanding amount			110,300,000			$ 110,300,000
Credit facility, Interest rate in period (as a percent)						2.00%
Aggregate elected commitment			815,000,000			$ 815,000,000
Letter of Credit | Senior Secured Credit Facility
Debt Instrument [Line Items]
Maximum borrowing capacity			20,000,000.0			20,000,000.0
Letters of credit outstanding			$ 0			$ 0				$ 0
Minimum | Line of Credit | Senior Secured Credit Facility
Debt Instrument [Line Items]
Line of credit facility, unused capacity, commitment fee percentage						0.375%
Maximum | Line of Credit | Senior Secured Credit Facility
Debt Instrument [Line Items]
Line of credit facility, unused capacity, commitment fee percentage						0.50%

[1] Loss on early redemption of debt was allocated to the exploration and production segment based on gross property and equipment as of June 30, 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of June 30, 2015.

[2] Loss on early redemption of debt was allocated to the exploration and production segment based on gross property and equipment as of June 30, 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of June 30, 2015.

[3] Debt issuance costs related to our Senior Secured Credit Facility are recorded in "Other assets, net" on the unaudited consolidated balance sheets.

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Debt - Fair value of debt (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Carrying value
Fair value of debt
Debt	$ 1,410,318	$ 1,435,000
Carrying value | Senior Notes | January 2022 Notes
Fair value of debt
Debt	450,000	450,000
Carrying value | Senior Notes | May 2022 Notes
Fair value of debt
Debt	500,000	500,000
Carrying value | Senior Notes | March 2023 Notes
Fair value of debt
Debt	350,000	350,000
Carrying value | Senior Secured Credit Facility | Line of Credit
Fair value of debt
Debt	110,318	135,000
Fair value
Fair value of debt
Debt	1,388,040	1,284,294
Fair value | Senior Notes | January 2022 Notes
Fair value of debt
Debt	426,564	388,301
Fair value | Senior Notes | May 2022 Notes
Fair value of debt
Debt	501,250	460,000
Fair value | Senior Notes | March 2023 Notes
Fair value of debt
Debt	349,965	301,000
Fair value | Senior Secured Credit Facility | Line of Credit
Fair value of debt
Debt	$ 110,261	$ 134,993

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Debt - Debt issuance costs (Details) - USD ($)		Jun. 30, 2016	Dec. 31, 2015	Mar. 18, 2015	Jan. 23, 2014	Apr. 27, 2012
Debt Instrument [Line Items]
Long-term debt		$ 1,410,318,000	$ 1,435,000,000
Debt issuance costs, net		(17,441,000)	(18,774,000)
Long-term debt, net		1,392,877,000	1,416,226,000
Senior Notes | January 2022 Notes
Debt Instrument [Line Items]
Long-term debt		450,000,000	450,000,000		$ 450,000,000.0
Debt issuance costs, net		(5,451,000)	(5,939,000)
Long-term debt, net		444,549,000	444,061,000
Senior Notes | May 2022 Notes
Debt Instrument [Line Items]
Long-term debt		500,000,000	500,000,000			$ 500,000,000
Debt issuance costs, net		(6,624,000)	(7,066,000)
Long-term debt, net		493,376,000	492,934,000
Senior Notes | March 2023 Notes
Debt Instrument [Line Items]
Long-term debt		350,000,000	350,000,000	$ 350,000,000.0
Debt issuance costs, net		(5,366,000)	(5,769,000)
Long-term debt, net		344,634,000	344,231,000
Senior Secured Credit Facility | Line of Credit
Debt Instrument [Line Items]
Long-term debt	[1]	110,318,000	135,000,000
Debt issuance costs, net	[1]	0	0
Long-term debt, net	[1]	$ 110,318,000	$ 135,000,000

[1] Debt issuance costs related to our Senior Secured Credit Facility are recorded in "Other assets, net" on the unaudited consolidated balance sheets.

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Employee compensation - Employee compensation and Restricted stock awards - Narrative (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Mar. 31, 2016
Restricted Stock Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation not yet recognized	$ 44.3
Stock-based compensation not yet recognized, period for recognition (in years)	2 years 3 months 4 days
Restricted Stock Awards | One Year From Grant Date
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage	100.00%
Restricted Stock Awards | One Year From Grant Date
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage	33.00%
Restricted Stock Awards | Two Years From Grant Date
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage	33.00%
Restricted Stock Awards | Three Years From Grant Date
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage	34.00%
Restricted Stock Awards | Vesting In Two Years
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage	50.00%
Restricted Stock Awards | Vesting In Three Years
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage	50.00%
Restricted Stock Awards | Three Years From Grant Date
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting percentage	100.00%
Long-Term Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares available for issuance	24,350,000	10,000,000

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Employee compensation - Restricted Stock Awards - outstanding restricted stock awards (Details) - Restricted Stock Awards shares in Thousands	6 Months Ended
	Jun. 30, 2016 $ / shares shares
Restricted stock awards
Outstanding at the beginning of the period (in shares) | shares	2,539
Granted (in shares) | shares	2,968
Forfeited (in shares) | shares	(221)
Vested (in shares) | shares	(1,124)	[1]
Outstanding at the end of the period (in shares) | shares	4,162
Weighted-average grant date fair value (per award)
Outstanding at the beginning of the period (in dollars per share) | $ / shares	$ 15.26
Granted (in dollars per share) | $ / shares	12.27
Forfeited (in dollars per share) | $ / shares	15.16
Vested (in dollars per share) | $ / shares	16.06	[1]
Outstanding at the end of the period (in dollars per share) | $ / shares	$ 12.92

[1] The vesting of certain restricted stock awards could result in federal and state income tax expense or benefit related to the difference between the market price of the common stock at the date of vesting and the date of grant. See Note 7 for additional discussion regarding the tax impact of vested stock awards.

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Employee compensation - Restricted Stock Option Awards - Narrative (Details) (Details) - Restricted Stock Option Awards $ in Millions			6 Months Ended
	May 25, 2016 shares	Apr. 01, 2016 shares	Jun. 30, 2016 USD ($) anniversary installment shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Requisite service period of the awards			4 years
Share-based compensation, not yet recognized, stock options | $			$ 13.5
Stock-based compensation not yet recognized, period for recognition (in years)			2 years 6 months 18 days
Granted (in shares)			1,016,000
Share-based compensation, expiration period			10 years
Expiration period, termination caused by death			1 year
Expiration period, termination without cause			90 days
Long-Term Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of installments over which awards vest and are exercisable | installment			4
Number of anniversaries over which awards vest and are exercisable | anniversary			4
April 1, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)		22,324
May 25, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	994,022

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Employee compensation - Restricted Stock Option Awards - stock option award activity (Details) - Restricted Stock Option Awards - USD ($) $ / shares in Units, shares in Thousands		6 Months Ended	12 Months Ended
		Jun. 30, 2016	Dec. 31, 2015
Restricted stock option awards
Outstanding at the beginning of the period (in shares)		1,778
Granted (in shares)		1,016
Exercised (in shares)		(6)
Expired or canceled (in shares)		(35)
Forfeited (in shares)		(229)
Outstanding at the end of the period (in shares)		2,524	1,778
Vested and exercisable at end of period (in shares)	[1]	916
Expected to vest at end of period (in shares)	[2]	1,600
Weighted-average price (per option)
Outstanding at the beginning of the period (in dollars per share)		$ 17.86
Granted (in dollars per share)		4.18
Exercised (in dollars per share)		11.93
Expired or cancelled (in dollars per share)		22.40
Forfeited (in dollars per share)		13.62
Outstanding at end of the period (in dollars per share)		12.69	$ 17.86
Vested and exercisable at end of period (in dollars per share)	[1]	19.49
Expected to vest at end of period (in dollars per share)	[2]	$ 8.75
Weighted-average remaining contractual term (years)
Outstanding at the beginning of the period		8 years 22 days	7 years 10 months 28 days
Outstanding at the end of the period		8 years 22 days	7 years 10 months 28 days
Vested and exercisable at the end of the period	[1]	6 years 4 months 28 days
Expected to vest at end of period	[2]	9 years 7 days
Aggregate intrinsic value of vested and exercisable options		$ 0
Aggregate intrinsic value of expected to vest options		$ 6,100,000

[1] The vested and exercisable options as of June 30, 2016 had no aggregate intrinsic value.

[2] The restricted stock options expected to vest as of June 30, 2016 had $6.1 million aggregate intrinsic value.

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Employee compensation - Restricted stock option awards assumptions used to estimate the fair value (Details) - Restricted Stock Option Awards - $ / shares		May 25, 2016	Apr. 01, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate	[1]	1.58%	1.44%
Expected option life	[2]	6 years 3 months	6 years 3 months
Expected volatility	[3]	61.94%	61.34%
Fair value per stock option		$ 9.75	$ 4.44

[1] United States Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, correlating the treasury yield terms to the expected life of the option.

[2] As the Company had limited exercise history at the time of valuation relating to terminations and modifications, expected option life assumptions were developed using the simplified method in accordance with GAAP.

[3] The Company utilized its own historical volatility in order to develop the expected volatility.

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Employee compensation - Restricted Stock Option Awards - percentage of options exercisable (Details) - Restricted Stock Option Awards	6 Months Ended
	Jun. 30, 2016
Less than one
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Incremental percentage of option exercisable	0.00%
Cumulative percentage of option exercisable	0.00%
One
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Incremental percentage of option exercisable	25.00%
Cumulative percentage of option exercisable	25.00%
Two
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Incremental percentage of option exercisable	25.00%
Cumulative percentage of option exercisable	50.00%
Three
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Incremental percentage of option exercisable	25.00%
Cumulative percentage of option exercisable	75.00%
Four
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Incremental percentage of option exercisable	25.00%
Cumulative percentage of option exercisable	100.00%

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Employee compensation - Performance Share Awards - Narrative (Details) - Performance Share Awards - USD ($) $ in Millions			6 Months Ended
	May 25, 2016	Apr. 01, 2016	Jun. 30, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Requisite service period of the awards			3 years
Outstanding shares			2,428,000	874,000
Granted (in shares)			1,801,000
Stock-based compensation not yet recognized			$ 35.3
Stock-based compensation not yet recognized, period for recognition			2 years 5 months 19 days
April 1, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)		32,495
May 25, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)	1,768,297
2016 Performance Share Awards | April 1, 2016 and May 25, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding shares			1,742,469
2015 Performance Share Awards | February 27, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding shares			475,518
2014 Performance Share Awards | February 27, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding shares			210,126

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Employee compensation - Performance Share Awards - award activity (Details) - Performance Share Awards - $ / shares shares in Thousands				6 Months Ended
		May 25, 2016	Apr. 01, 2016	Jun. 30, 2016
Performance share awards
Outstanding at the beginning of the period (in shares)				874
Granted (in shares)				1,801
Forfeited (in shares)				(247)
Vested (in shares)				0
Outstanding at the end of the period (in shares)				2,428
Weighted-average grant date fair value (per award)
Outstanding at the beginning of the period (in dollars per share)				$ 20.06
Granted (in dollars per share)		$ 17.86	$ 9.83	17.71
Forfeited (in dollars per share)				19.69
Vested (in dollars per share)	[1]			0.00
Outstanding at the end of the period (in dollars per share)				$ 18.36

[1] The vesting of certain restricted stock awards could result in federal and state income tax expense or benefit related to the difference between the market price of the common stock at the date of vesting and the date of grant. See Note 7 for additional discussion regarding the tax impact of vested stock awards.

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Employee compensation - Performance share awards assumptions used to estimate the fair value (Details) - Performance Share Awards - $ / shares				6 Months Ended
		May 25, 2016	Apr. 01, 2016	Jun. 30, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate	[1]	1.02%	0.87%
Dividend yield		0.00%	0.00%
Expected volatility	[2]	74.73%	71.54%
Share Price		$ 12.36	$ 7.71
Granted (in dollars per share)		$ 17.86	$ 9.83	$ 17.71

[1] The risk-free rate was derived using a term-matched zero-coupon yield derived from the Treasury Constant Maturities yield curve on the grant date.

[2] The Company utilized its own historical volatility over a lookback period equal to the length of the remaining performance period from the grant date in order to develop the expected volatility.

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Employee compensation - Stock-based Compensation Award Expense (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total stock-based compensation, gross	$ 7,062	$ 7,177	$ 11,682	$ 11,680
Less amounts capitalized in oil and natural gas properties	(989)	(909)	(1,771)	(624)
Total stock-based compensation, net of amounts capitalized	6,073	6,268	9,911	11,056
Restricted Stock Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total stock-based compensation, gross	4,692	4,520	8,460	7,458
Restricted Stock Option Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total stock-based compensation, gross	777	1,279	1,401	1,949
Restricted Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total stock-based compensation, gross	$ 1,593	$ 1,378	$ 1,821	$ 2,273

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Employee compensation - Performance unit awards - Narrative (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended				6 Months Ended
	Jun. 30, 2016	Mar. 31, 2016	Jun. 30, 2015	Mar. 31, 2015	Jun. 30, 2016	Jun. 30, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Net stock-based compensation expense	$ 6,073		$ 6,268		$ 9,911	$ 11,056
Performance Unit Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity instruments other than options, cash paid per unit (in dollars per share)		$ 143.75		$ 100.00
Net stock-based compensation expense			$ 700			$ 1,700
February 15, 2013 | Performance Unit Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vested (in shares)		44,481
February 3, 2012 | Performance Unit Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vested (in shares)				27,381

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Income taxes - Current and deferred income tax benefit (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Income Tax Disclosure [Abstract]
Current taxes	$ 0	$ 0	$ 0	$ 0
Deferred taxes	0	221,846	0	218,203
Income tax benefit	$ 0	$ 221,846	$ 0	$ 218,203

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Income taxes - Reconciliation of income tax benefit (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Income Tax Disclosure [Abstract]
Effective Income Tax Rate Reconciliation, Percent		36.00%		35.00%
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Income tax benefit computed by applying the statutory rate	$ 25,001	$ 216,608	$ 88,131	$ 215,498
State income tax and change in valuation allowance	(541)	5,776	187	5,867
Non-deductible stock-based compensation	0	(15)	0	(106)
Stock-based compensation tax deficiency	(190)	(381)	(4,012)	(2,838)
Increase in deferred tax valuation allowance	(24,323)	(11)	(84,218)	(16)
Other items	53	(131)	(88)	(202)
Income tax benefit	$ 0	$ 221,846	$ 0	$ 218,203

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Income taxes - Tax impact of shortfalls (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred income tax stock-based compensation tax deficiency	$ (192)	$ (388)	$ (4,067)	$ (2,889)
Restricted Stock Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred income tax stock-based compensation tax deficiency	(182)	(388)	(4,057)	(2,889)
Restricted Stock Option Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred income tax stock-based compensation tax deficiency	$ (10)	$ 0	$ (10)	$ 0

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Income taxes - Deferred tax assets and liabilities (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Significant components of deferred tax assets (liabilities)
Oil and natural gas properties, midstream service assets and other fixed assets	$ 282,612	$ 306,997
Net operating loss carry-forward	528,625	479,022
Derivatives	(41,577)	(98,675)
Stock-based compensation	9,340	11,597
Equity method investee	(25,612)	(31,711)
Accrued bonus	2,544	4,763
Capitalized interest	2,173	2,525
Other	2,901	2,820
Net deferred tax asset before valuation allowance	761,006	677,338
Valuation allowance	(761,006)	(677,338)
Net deferred tax asset	$ 0	$ 0

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Income taxes - Additional Information (Details) - USD ($)	6 Months Ended		12 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Potential adjustments to additional paid in capital for income tax benefit from share-based compensation	$ 4,500,000
Operating loss carry-forward
Deferred tax assets, valuation allowance	761,006,000		$ 677,338,000
Unrecognized tax benefits	$ 0		0
Effective income tax rate, federal (percent)	35.00%	35.00%
Valuation allowance adjustment	$ 83,700,000		$ 676,000,000
Internal Revenue Service (IRS) | Federal
Operating loss carry-forward
Operating Loss Carryforwards	1,500,000,000
State of Oklahoma | State
Operating loss carry-forward
Operating Loss Carryforwards	$ 41,000,000

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Derivatives - Commodity Derivatives (Details) - Derivatives not designated as hedges $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2016 USD ($) contract	Jun. 30, 2015 USD ($)	Jun. 30, 2016 USD ($) contract	Jun. 30, 2015 USD ($)
Derivative [Line Items]
Number of open derivative contracts | contract		25		25
Crude Oil
Derivative [Line Items]
Number of restructuring derivatives | contract				2
Commodity derivatives
Derivative [Line Items]
Termination amount | $	[1]	$ 0	$ 0	$ 80,000	$ 0
Commodity derivatives | Crude Oil
Derivative [Line Items]
Termination amount | $				$ 80,000

[1] The settlements amount for the six months ended June 30, 2016 includes $4.0 million in deferred premiums which were settled net with the early terminated contracts from which they derive.

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Derivatives - Commodity derivative contracts' collar floors terminated (Details) - January 2017 - December 2017 - Derivatives not designated as hedges - Early Contract Termination - Crude Oil	Jun. 30, 2016 bbl $ / bbl
Derivative [Line Items]
Aggregate volumes (Bbl) | bbl	2,263,000
Floor Price (dollars per Bbl) | $ / bbl	80

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Derivatives - Commodity derivative contracts' collar floors entered into (Details) $ in Thousands		6 Months Ended
		Jun. 30, 2016 USD ($) bbl MMBTU $ / bbl $ / MMBTU	Jun. 30, 2015 USD ($)
Derivative [Line Items]
Cash premiums paid for derivatives | $		$ 84,263	$ 2,670
Put Option January 2017 to December 2017 | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl and MMBtu) | bbl	[1]	2,263,000
Floor Price (dollars per Bbl and MMBtu) | $ / bbl	[1]	60
Cash premiums paid for derivatives | $		$ 40,000
Put Option January 2017 to December 2017 | Natural Gas
Derivative [Line Items]
Aggregate volumes (Bbl and MMBtu) | MMBTU	[2]	8,040,000
Floor Price (dollars per Bbl and MMBtu)	[2]	2.50
Put Option January 2017 to December 2018 | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl and MMBtu) | bbl	[3]	2,098,750
Floor Price (dollars per Bbl and MMBtu) | $ / bbl	[3]	60.00
Cash premiums paid for derivatives | $		$ 40,000
Put Option May 2016 to December 2016 | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl and MMBtu) | bbl	[4]	600,000
Floor Price (dollars per Bbl and MMBtu) | $ / bbl	[4]	40
Derivative, deferred premium | $		$ 1,200
Swap January 2018 to December 2018 | Crude Oil
Derivative [Line Items]
Aggregate volumes (Bbl and MMBtu) | bbl		1,095,000
Floor Price (dollars per Bbl and MMBtu) | $ / bbl		52.12
Put Option January 2018 to December 2018 | Natural Gas
Derivative [Line Items]
Aggregate volumes (Bbl and MMBtu) | MMBTU	[2]	8,220,000
Floor Price (dollars per Bbl and MMBtu)	[2]	2.50
Collar January 2017 - December 2017 | Natural Gas
Derivative [Line Items]
Aggregate volumes (Bbl and MMBtu) | MMBTU	[2]	5,256,000
Floor Price (dollars per Bbl and MMBtu)	[2]	2.50
Ceiling price (dollars per MMBtu)	[2]	3.05
Collar January 2018 - December 2018 | Natural Gas
Derivative [Line Items]
Aggregate volumes (Bbl and MMBtu) | MMBTU	[2]	4,635,500
Floor Price (dollars per Bbl and MMBtu)	[2]	2.50
Ceiling price (dollars per MMBtu)	[2]	3.60
Put Option and Collars January 2017 and 2018 to December 2017 and 2018 | Natural Gas
Derivative [Line Items]
Derivative, deferred premium | $		$ 5,100

[1] As part of the Company's hedge restructuring, this put replaced the early terminated put portion of the restructured derivative contract collars. A premium of $40.0 million was paid at contract inception.

[2] There are $5.1 million in deferred premiums associated with these contracts.

[3] As part of the Company's hedge restructuring, a premium of $40.0 million was paid at contract inception.

[4] There are $1.2 million in deferred premiums associated with this contract.

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Derivatives - Gain (loss) on derivatives (Details) - Derivatives not designated as hedges - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Commodity derivatives
Derivative financial instruments
Cash settlements received for matured derivatives, net		$ 47,382	$ 46,596	$ 113,319	$ 109,737
Cash settlements received for early terminations of derivatives, net	[1]	0	0	80,000	0
Deferred premium				4,000
Derivative
Derivative financial instruments
Cash settlements received for derivatives, net		$ 47,382	$ 46,596	$ 193,319	$ 109,737

[1] The settlements amount for the six months ended June 30, 2016 includes $4.0 million in deferred premiums which were settled net with the early terminated contracts from which they derive.

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Derivatives - Derivative positions (Details) - Derivatives not designated as hedges	6 Months Ended
	Jun. 30, 2016 MMBTU $ / bbl $ / MMBTU bbl
Puts 2016 | Crude Oil | Puts
Derivative [Line Items]
Hedged Volume (Bbl) | bbl	1,098,000
Weighted-average price (Bbl/MMbtu)	42.95
Puts 2016 | Natural Gas | Puts
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	0.00
Hedged Volume (MMbtu) | MMBTU	0
Puts 2017 | Crude Oil | Puts
Derivative [Line Items]
Hedged Volume (Bbl) | bbl	1,049,375
Weighted-average price (Bbl/MMbtu)	60.00
Puts 2017 | Natural Gas | Puts
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	2.50
Hedged Volume (MMbtu) | MMBTU	8,040,000
Puts 2018 | Crude Oil | Puts
Derivative [Line Items]
Hedged Volume (Bbl) | bbl	1,049,375
Weighted-average price (Bbl/MMbtu)	60.00
Puts 2018 | Natural Gas | Puts
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	2.50
Hedged Volume (MMbtu) | MMBTU	8,220,000
Swaps 2016 | Crude Oil | Swaps
Derivative [Line Items]
Hedged Volume (Bbl) | bbl	791,200
Weighted-average price (Bbl/MMbtu)	84.82
Swaps 2018 | Crude Oil | Swaps
Derivative [Line Items]
Hedged Volume (Bbl) | bbl	1,095,000
Weighted-average price (Bbl/MMbtu)	52.12
Collars 2016 | Crude Oil | Collars
Derivative [Line Items]
Hedged Volume (Bbl) | bbl	1,833,500
Collars 2016 | Natural Gas | Collars
Derivative [Line Items]
Hedged Volume (MMbtu) | MMBTU	9,384,000
Collars 2016 | Floor | Crude Oil | Collars
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu)	73.98
Collars 2016 | Floor | Natural Gas | Collars
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	3.00
Collars 2016 | Ceiling | Crude Oil | Collars
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu)	89.62
Collars 2016 | Ceiling | Natural Gas | Collars
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	5.60
Collars 2017 | Crude Oil | Collars
Derivative [Line Items]
Hedged Volume (Bbl) | bbl	2,628,000
Collars 2017 | Natural Gas | Collars
Derivative [Line Items]
Hedged Volume (MMbtu) | MMBTU	10,731,000
Collars 2017 | Floor | Crude Oil | Collars
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu)	60.00
Collars 2017 | Floor | Natural Gas | Collars
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	2.76
Collars 2017 | Ceiling | Crude Oil | Collars
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu)	97.22
Collars 2017 | Ceiling | Natural Gas | Collars
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	3.53
Collars 2018 | Crude Oil | Collars
Derivative [Line Items]
Hedged Volume (Bbl) | bbl	0
Collars 2018 | Natural Gas | Collars
Derivative [Line Items]
Hedged Volume (MMbtu) | MMBTU	4,635,500
Collars 2018 | Floor | Crude Oil | Collars
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu)	0.00
Collars 2018 | Floor | Natural Gas | Collars
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	2.50
Collars 2018 | Ceiling | Crude Oil | Collars
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu)	0.00
Collars 2018 | Ceiling | Natural Gas | Collars
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	3.60
Total Commodity Derivatives 2016 | Floor | Crude Oil
Derivative [Line Items]
Hedged Volume (Bbl) | bbl	3,722,700
Weighted-average price (Bbl/MMbtu)	67.13
Total Commodity Derivatives 2016 | Floor | Natural Gas
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	3.00
Hedged Volume (MMbtu) | MMBTU	9,384,000
Total Commodity Derivatives 2016 | Ceiling | Crude Oil
Derivative [Line Items]
Hedged Volume (Bbl) | bbl	2,624,700
Weighted-average price (Bbl/MMbtu)	88.18
Total Commodity Derivatives 2016 | Ceiling | Natural Gas
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	5.60
Hedged Volume (MMbtu) | MMBTU	9,384,000
Total Commodity Derivatives 2017 | Floor | Crude Oil
Derivative [Line Items]
Hedged Volume (Bbl) | bbl	3,677,375
Weighted-average price (Bbl/MMbtu)	60.00
Total Commodity Derivatives 2017 | Floor | Natural Gas
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	2.65
Hedged Volume (MMbtu) | MMBTU	18,771,000
Total Commodity Derivatives 2017 | Ceiling | Crude Oil
Derivative [Line Items]
Hedged Volume (Bbl) | bbl	2,628,000
Weighted-average price (Bbl/MMbtu)	97.22
Total Commodity Derivatives 2017 | Ceiling | Natural Gas
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	3.53
Hedged Volume (MMbtu) | MMBTU	10,731,000
Total Commodity Derivatives 2018 | Floor | Crude Oil
Derivative [Line Items]
Hedged Volume (Bbl) | bbl	2,144,375
Weighted-average price (Bbl/MMbtu)	55.98
Total Commodity Derivatives 2018 | Floor | Natural Gas
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	2.50
Hedged Volume (MMbtu) | MMBTU	12,855,500
Total Commodity Derivatives 2018 | Ceiling | Crude Oil
Derivative [Line Items]
Hedged Volume (Bbl) | bbl	1,095,000
Weighted-average price (Bbl/MMbtu)	52.12
Total Commodity Derivatives 2018 | Ceiling | Natural Gas
Derivative [Line Items]
Weighted-average price (Bbl/MMbtu) | $ / MMBTU	3.60
Hedged Volume (MMbtu) | MMBTU	4,635,500

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Fair value measurements - Fair value hierarchy (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Assets, Fair Value Disclosure [Abstract]
Derivative asset, current	$ 88,965	$ 198,805
Derivative asset, noncurrent	32,680	77,443
Liabilities, Fair Value Disclosure [Abstract]
Derivative liability, current	(1,480)	0
Derivative liability, noncurrent	(3,740)	0
Recurring
Liabilities, Fair Value Disclosure [Abstract]
Net derivative position	116,425	276,248
Recurring | Crude Oil | Oil derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative asset, current	92,542	194,940
Derivative asset, noncurrent	33,181	80,302
Liabilities, Fair Value Disclosure [Abstract]
Derivative liability, current	515	0
Derivative liability, noncurrent	(1,820)	0
Recurring | Crude Oil | Oil deferred premiums
Assets, Fair Value Disclosure [Abstract]
Derivative asset, current	(5,467)	(9,301)
Derivative asset, noncurrent	(501)	(4,877)
Liabilities, Fair Value Disclosure [Abstract]
Derivative liability, current	(1,317)	0
Derivative liability, noncurrent	0	0
Recurring | Natural Gas | Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative asset, current	2,293	13,166
Derivative asset, noncurrent	0	2,459
Liabilities, Fair Value Disclosure [Abstract]
Derivative liability, current	426	0
Derivative liability, noncurrent	1,950	0
Recurring | Natural Gas | Natural gas deferred premiums
Assets, Fair Value Disclosure [Abstract]
Derivative asset, current	(403)	0
Derivative asset, noncurrent	0	(441)
Liabilities, Fair Value Disclosure [Abstract]
Derivative liability, current	(1,104)	0
Derivative liability, noncurrent	(3,870)	0
Recurring | Current Assets | Crude Oil | Oil derivatives
Assets, Fair Value Disclosure [Abstract]
Amounts offset	(515)	0
Recurring | Current Assets | Crude Oil | Oil deferred premiums
Assets, Fair Value Disclosure [Abstract]
Amounts offset	(5,467)	(9,301)
Recurring | Current Assets | Natural Gas | Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Amounts offset	(1,165)	0
Recurring | Current Assets | Natural Gas | Natural gas deferred premiums
Assets, Fair Value Disclosure [Abstract]
Amounts offset	(403)	0
Recurring | Noncurrent Assets | Crude Oil | Oil derivatives
Assets, Fair Value Disclosure [Abstract]
Amounts offset	0	0
Recurring | Noncurrent Assets | Crude Oil | Oil deferred premiums
Assets, Fair Value Disclosure [Abstract]
Amounts offset	(501)	(4,877)
Recurring | Noncurrent Assets | Natural Gas | Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Amounts offset	(2,724)	0
Recurring | Noncurrent Assets | Natural Gas | Natural gas deferred premiums
Assets, Fair Value Disclosure [Abstract]
Amounts offset	0	(441)
Recurring | Current Liabilities | Crude Oil | Oil derivatives
Liabilities, Fair Value Disclosure [Abstract]
Amount offset	515	0
Recurring | Current Liabilities | Crude Oil | Oil deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Amount offset	5,467	9,301
Recurring | Current Liabilities | Natural Gas | Natural gas derivatives
Liabilities, Fair Value Disclosure [Abstract]
Amount offset	1,165	0
Recurring | Current Liabilities | Natural Gas | Natural gas deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Amount offset	403	0
Recurring | Noncurrent Liabilities | Crude Oil | Oil derivatives
Liabilities, Fair Value Disclosure [Abstract]
Amount offset	0	0
Recurring | Noncurrent Liabilities | Crude Oil | Oil deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Amount offset	501	4,877
Recurring | Noncurrent Liabilities | Natural Gas | Natural gas derivatives
Liabilities, Fair Value Disclosure [Abstract]
Amount offset	2,724	0
Recurring | Noncurrent Liabilities | Natural Gas | Natural gas deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Amount offset	0	441
Recurring | Fair value
Liabilities, Fair Value Disclosure [Abstract]
Net derivative position	116,425	276,248
Recurring | Fair value | Current Assets | Crude Oil | Oil derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	93,057	194,940
Recurring | Fair value | Current Assets | Crude Oil | Oil deferred premiums
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring | Fair value | Current Assets | Natural Gas | Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	3,458	13,166
Recurring | Fair value | Current Assets | Natural Gas | Natural gas deferred premiums
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring | Fair value | Noncurrent Assets | Crude Oil | Oil derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	33,181	80,302
Recurring | Fair value | Noncurrent Assets | Crude Oil | Oil deferred premiums
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring | Fair value | Noncurrent Assets | Natural Gas | Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	2,724	2,459
Recurring | Fair value | Noncurrent Assets | Natural Gas | Natural gas deferred premiums
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring | Fair value | Current Liabilities | Crude Oil | Oil derivatives
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0	0
Recurring | Fair value | Current Liabilities | Crude Oil | Oil deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	(6,784)	(9,301)
Recurring | Fair value | Current Liabilities | Natural Gas | Natural gas derivatives
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	(739)	0
Recurring | Fair value | Current Liabilities | Natural Gas | Natural gas deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	(1,507)	0
Recurring | Fair value | Noncurrent Liabilities | Crude Oil | Oil derivatives
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	(1,820)	0
Recurring | Fair value | Noncurrent Liabilities | Crude Oil | Oil deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	(501)	(4,877)
Recurring | Fair value | Noncurrent Liabilities | Natural Gas | Natural gas derivatives
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	(774)	0
Recurring | Fair value | Noncurrent Liabilities | Natural Gas | Natural gas deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	(3,870)	(441)
Recurring | Level 1
Liabilities, Fair Value Disclosure [Abstract]
Net derivative position	0	0
Recurring | Level 1 | Current Assets | Crude Oil | Oil derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring | Level 1 | Current Assets | Crude Oil | Oil deferred premiums
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring | Level 1 | Current Assets | Natural Gas | Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring | Level 1 | Current Assets | Natural Gas | Natural gas deferred premiums
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring | Level 1 | Noncurrent Assets | Crude Oil | Oil derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring | Level 1 | Noncurrent Assets | Crude Oil | Oil deferred premiums
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring | Level 1 | Noncurrent Assets | Natural Gas | Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring | Level 1 | Noncurrent Assets | Natural Gas | Natural gas deferred premiums
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring | Level 1 | Current Liabilities | Crude Oil | Oil derivatives
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0	0
Recurring | Level 1 | Current Liabilities | Crude Oil | Oil deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0	0
Recurring | Level 1 | Current Liabilities | Natural Gas | Natural gas derivatives
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0	0
Recurring | Level 1 | Current Liabilities | Natural Gas | Natural gas deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0	0
Recurring | Level 1 | Noncurrent Liabilities | Crude Oil | Oil derivatives
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0	0
Recurring | Level 1 | Noncurrent Liabilities | Crude Oil | Oil deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0	0
Recurring | Level 1 | Noncurrent Liabilities | Natural Gas | Natural gas derivatives
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0	0
Recurring | Level 1 | Noncurrent Liabilities | Natural Gas | Natural gas deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0	0
Recurring | Level 2
Liabilities, Fair Value Disclosure [Abstract]
Net derivative position	129,087	290,867
Recurring | Level 2 | Current Assets | Crude Oil | Oil derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	93,057	194,940
Recurring | Level 2 | Current Assets | Crude Oil | Oil deferred premiums
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring | Level 2 | Current Assets | Natural Gas | Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	3,458	13,166
Recurring | Level 2 | Current Assets | Natural Gas | Natural gas deferred premiums
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring | Level 2 | Noncurrent Assets | Crude Oil | Oil derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	33,181	80,302
Recurring | Level 2 | Noncurrent Assets | Crude Oil | Oil deferred premiums
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring | Level 2 | Noncurrent Assets | Natural Gas | Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	2,724	2,459
Recurring | Level 2 | Noncurrent Assets | Natural Gas | Natural gas deferred premiums
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring | Level 2 | Current Liabilities | Crude Oil | Oil derivatives
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0	0
Recurring | Level 2 | Current Liabilities | Crude Oil | Oil deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0	0
Recurring | Level 2 | Current Liabilities | Natural Gas | Natural gas derivatives
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	(739)	0
Recurring | Level 2 | Current Liabilities | Natural Gas | Natural gas deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0	0
Recurring | Level 2 | Noncurrent Liabilities | Crude Oil | Oil derivatives
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	(1,820)	0
Recurring | Level 2 | Noncurrent Liabilities | Crude Oil | Oil deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0	0
Recurring | Level 2 | Noncurrent Liabilities | Natural Gas | Natural gas derivatives
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	(774)	0
Recurring | Level 2 | Noncurrent Liabilities | Natural Gas | Natural gas deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0	0
Recurring | Level 3
Liabilities, Fair Value Disclosure [Abstract]
Net derivative position	(12,662)	(14,619)
Recurring | Level 3 | Current Assets | Crude Oil | Oil derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring | Level 3 | Current Assets | Crude Oil | Oil deferred premiums
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring | Level 3 | Current Assets | Natural Gas | Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring | Level 3 | Current Assets | Natural Gas | Natural gas deferred premiums
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring | Level 3 | Noncurrent Assets | Crude Oil | Oil derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring | Level 3 | Noncurrent Assets | Crude Oil | Oil deferred premiums
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring | Level 3 | Noncurrent Assets | Natural Gas | Natural gas derivatives
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring | Level 3 | Noncurrent Assets | Natural Gas | Natural gas deferred premiums
Assets, Fair Value Disclosure [Abstract]
Derivative assets before netting	0	0
Recurring | Level 3 | Current Liabilities | Crude Oil | Oil derivatives
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0	0
Recurring | Level 3 | Current Liabilities | Crude Oil | Oil deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	(6,784)	(9,301)
Recurring | Level 3 | Current Liabilities | Natural Gas | Natural gas derivatives
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0	0
Recurring | Level 3 | Current Liabilities | Natural Gas | Natural gas deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	(1,507)	0
Recurring | Level 3 | Noncurrent Liabilities | Crude Oil | Oil derivatives
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0	0
Recurring | Level 3 | Noncurrent Liabilities | Crude Oil | Oil deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	(501)	(4,877)
Recurring | Level 3 | Noncurrent Liabilities | Natural Gas | Natural gas derivatives
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	0	0
Recurring | Level 3 | Noncurrent Liabilities | Natural Gas | Natural gas deferred premiums
Liabilities, Fair Value Disclosure [Abstract]
Derivative liabilities before netting	$ (3,870)	$ (441)

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Fair value measurements - Narrative (Details) - Recurring - Level 3 - Commodity derivatives	6 Months Ended
	Jun. 30, 2016
Minimum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Discount rate (as a percent)	1.69%
Maximum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Discount rate (as a percent)	3.56%

XML

Fair value measurements - Cash payments required for deferred premium contracts (Details) $ in Thousands	Jun. 30, 2016 USD ($)
Fair Value Disclosures [Abstract]
Remaining 2016	$ 5,407
2017	5,354
2018	2,100
Total	$ 12,861

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Fair value measurements - Summary of changes in assets (liabilities) classified as Level 3 (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016		Jun. 30, 2015
Changes in assets classified as Level 3 measurements
Change in net present value of deferred premiums for derivatives				$ 133		$ 88
Deferred Premiums
Changes in assets classified as Level 3 measurements
Balance of Level 3 at beginning of period		$ (13,054)	$ (8,882)	(14,619)		(9,285)
Change in net present value of deferred premiums for derivatives		(61)	(45)	(133)		(88)
Purchases		(1,960)	(4,409)	(6,072)		(5,384)
Settlements		2,413	1,249	8,162	[1]	2,670
Balance of Level 3 at end of period		$ (12,662)	$ (12,087)	(12,662)		$ (12,087)
Restructuring Upon Early Termination | Deferred Premiums
Changes in assets classified as Level 3 measurements
Settlements	[1]			$ 3,900

[1] The amount for the six months ended June 30, 2016 includes $3.9 million which represents the present value of deferred premiums settled in the Company's restructuring upon their early termination.

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Net loss per share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Earnings Per Share, Basic and Diluted, Other Disclosures [Abstract]
Net loss—basic and diluted	$ (71,432)	$ (397,034)	$ (251,803)	$ (397,506)
Weighted-average common shares outstanding-basic (in shares)	217,564	211,078	214,562	186,886
Weighted-average common shares outstanding-diluted (in shares)	217,564	211,078	214,562	186,886
Net loss per share-basic (in dollars per share)	$ (0.33)	$ (1.88)	$ (1.17)	$ (2.13)
Net loss per share-diluted (in dollars per share)	$ (0.33)	$ (1.88)	$ (1.17)	$ (2.13)

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Commitments and contingencies (Details) $ in Millions	Jun. 30, 2016 USD ($)
Drilling Contracts
Unrecorded Unconditional Purchase Obligation [Line Items]
Future commitments	$ 3.0
Firm Sale And Transportation Commitments
Unrecorded Unconditional Purchase Obligation [Line Items]
Future commitments	$ 400.2

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Restructuring (Details) $ in Thousands		3 Months Ended		6 Months Ended
	Jan. 20, 2015 employee	Jun. 30, 2016 USD ($)	Jun. 30, 2015 USD ($)	Jun. 30, 2016 USD ($)	Jun. 30, 2015 USD ($)
Restructuring Cost and Reserve [Line Items]
Restructuring expenses | $		$ 0	$ 0	$ 0	$ 6,042
Reduction in Force (RIF)
Restructuring Cost and Reserve [Line Items]
Restructuring expenses | $				$ 0	$ 6,000
Workforce Reduction | Reduction in Force (RIF)
Restructuring Cost and Reserve [Line Items]
Expected number of positions eliminated | employee	75
Contract Termination | Reduction in Force (RIF)
Restructuring Cost and Reserve [Line Items]
Expected number of positions eliminated | employee	24

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Variable interest entity (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Schedule of Equity Method Investments [Line Items]
Contributions to equity method investee			$ 42,681	$ 14,495
Minimum volume commitments	$ 0	$ 3,579	0	5,235
Medallion Gathering And Processing LLC | Variable Interest Entity, Not Primary Beneficiary
Schedule of Equity Method Investments [Line Items]
Contributions to equity method investee	$ 16,000		$ 42,700	$ 14,500
Ownership percentage	49.00%		49.00%
Equity method investment ownership percentage held by investment partner	51.00%		51.00%
Voting percentage required for key decisions			75.00%
Minimum volume commitments		$ 3,000

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Related Parties - Consolidated Statement of Operations related to Medallion (Details) - Equity Method Investee - Medallion Gathering And Processing LLC - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Midstream service revenues
Related Party Transaction [Line Items]
Related party revenues	$ 0	$ 390	$ 0	$ 487
Minimum volume commitments
Related Party Transaction [Line Items]
Lease operating expenses	0	3,579	0	5,235
Interest and other income
Related Party Transaction [Line Items]
Related party revenues	$ 0	$ 0	$ 0	$ 108

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Related Parties - Balance Sheet related to Medallion (Details) - USD ($) $ in Thousands		Jun. 30, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Accounts receivable, net		$ 88,543	$ 87,699
Equity Method Investee | Medallion Gathering And Processing LLC
Related Party Transaction [Line Items]
Accounts receivable, net		0	1,163
Equity Method Investee | Medallion Gathering And Processing LLC | Other assets, net
Related Party Transaction [Line Items]
Related party assets and liabilities	[1]	1,025	1,025
Equity Method Investee | Medallion Gathering And Processing LLC | Other current liabilities
Related Party Transaction [Line Items]
Related party assets and liabilities	[2]	$ (102)	$ (27,583)

[1] (1)Amounts included in "Other assets, net" above represent LMS owned line-fill in Medallion's pipeline.

[2] (2)Amounts included in "Other current liabilities" above represent LMS' accrued line-fill purchase in Medallion's pipeline as of June 30, 2016 and capital contribution payable to Medallion as of December 31, 2015.

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Related Parties - Consolidated Statement of Operations related to Targa Resources (Details) - Affiliated Entity - Targa Resources Corp. - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Oil, NGL and natural gas sales
Related Party Transaction [Line Items]
Related party revenues	$ 18,112	$ 34,012	$ 35,917	$ 53,643
Midstream service revenues
Related Party Transaction [Line Items]
Related party revenues	$ 102	$ 0	$ 237	$ 0

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Related Parties - Balance Sheet related to Targa Resources (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Affiliated Entity | Targa Resources Corp.
Related Party Transaction [Line Items]
Accounts receivable, net	$ 9,337	$ 6,097

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Related Parties - Archrock Partners, L.P. (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Related Party Transaction [Line Items]
Midstream service assets			$ 3,425	$ 34,137
Archrock Partners, L.P. | Affiliated Entity
Related Party Transaction [Line Items]
Accounts payable	$ 0		0		$ 13
Archrock Partners, L.P. | Affiliated Entity | Lease Operating Expenses
Related Party Transaction [Line Items]
Lease operating expenses	526	$ 391	1,001	776
Archrock Partners, L.P. | Affiliated Entity | Midstream Service Assets Capital Expenditures
Related Party Transaction [Line Items]
Midstream service assets	$ 0	$ 18	$ 20	$ 64

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Related Parties - Helmerich & Payne, Inc. (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Related Party Transaction [Line Items]
Oil and natural gas properties			$ 197,042	$ 374,508
Helmerich & Payne, Inc. | Affiliated Entity | Oil and Natural Gas Capital Expenditures
Related Party Transaction [Line Items]
Oil and natural gas properties	$ 0	$ 177	$ 0	$ 2,434

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Segments - Selected financial information (Details) - USD ($) $ in Thousands		3 Months Ended				6 Months Ended
		Jun. 30, 2016		Jun. 30, 2015		Jun. 30, 2016		Jun. 30, 2015
Segment Reporting Information [Line Items]
Oil, NGL and natural gas sales		$ 102,526		$ 125,554		$ 175,668		$ 243,672
Midstream service revenues		1,632		1,726		3,433		3,035
Sales of purchased oil		42,615		55,051		74,229		86,318
Total revenues		146,773		182,331		253,330		333,025
Lease operating expenses, including production tax		27,207		38,706		54,160		80,172
Midstream service expenses		1,178		5,176		1,787		8,406
Costs of purchased oil		44,012		54,417		76,958		85,617
General and administrative		20,502	[1]	23,208	[1]	39,953	[2]	45,063	[2]
Depletion, depreciation and amortization		34,177	[3]	72,112	[3]	75,655	[4]	144,054	[4]
Impairment expense		963		489,599		162,027		490,477
Other operating costs and expenses		860	[5]	593	[5]	1,704	[6]	7,214	[6]
Operating income (loss)		17,874		(501,480)		(158,914)		(527,978)
Income from equity method investee		3,696		2,914		5,994		2,481
Interest expense		(23,512)	[7]	(23,970)	[7]	(47,217)	[8]	(56,384)	[8]
Loss on early redemption of debt		0		(31,537)	[9]	0		(31,537)	[10]
Capital expenditures		(93,577)		(147,100)		(201,299)		(415,186)
Gross property and equipment	[11],[12]	5,846,670		5,427,620		5,846,670		5,427,620
Operating Segments | Exploration and production
Segment Reporting Information [Line Items]
Oil, NGL and natural gas sales		102,526		125,679		175,668		243,890
Midstream service revenues		0		0		0		0
Sales of purchased oil		0		0		0		0
Total revenues		102,526		125,679		175,668		243,890
Lease operating expenses, including production tax		29,793		41,423		59,157		85,268
Midstream service expenses		0		4,399		0		4,399
Costs of purchased oil		0		0		0		0
General and administrative		18,818	[1]	21,347	[1]	36,497	[2]	41,125	[2]
Depletion, depreciation and amortization		31,969	[3]	69,987	[3]	71,261	[4]	140,244	[4]
Impairment expense		963		489,599		162,027		490,366
Other operating costs and expenses		806	[5]	548	[5]	1,598	[6]	6,972	[6]
Operating income (loss)		20,177		(501,624)		(154,872)		(524,484)
Income from equity method investee		0		0		0		0
Interest expense		(22,050)	[7]	(22,845)	[7]	(44,353)	[8]	(53,932)	[8]
Loss on early redemption of debt				(30,056)	[9]			(30,056)	[10]
Capital expenditures		(92,089)		(133,259)		(197,874)		(380,872)
Gross property and equipment	[11],[12]	5,484,416		5,170,912		5,484,416		5,170,912
Operating Segments | Midstream and marketing
Segment Reporting Information [Line Items]
Oil, NGL and natural gas sales		0		221		0		333
Midstream service revenues		11,138		4,362		22,405		8,045
Sales of purchased oil		42,615		55,051		74,229		86,318
Total revenues		53,753		59,634		96,634		94,696
Lease operating expenses, including production tax		0		0		0		0
Midstream service expenses		6,572		998		13,081		4,340
Costs of purchased oil		44,012		54,417		76,958		85,617
General and administrative		1,684	[1]	1,861	[1]	3,456	[2]	3,938	[2]
Depletion, depreciation and amortization		2,208	[3]	2,125	[3]	4,394	[4]	3,810	[4]
Impairment expense		0		0		0		111
Other operating costs and expenses		54	[5]	45	[5]	106	[6]	242	[6]
Operating income (loss)		(777)		188		(1,361)		(3,362)
Income from equity method investee		3,696		2,914		5,994		2,481
Interest expense		(1,462)	[7]	(1,125)	[7]	(2,864)	[8]	(2,452)	[8]
Loss on early redemption of debt				(1,481)	[9]			(1,481)	[10]
Capital expenditures		(1,488)		(13,841)		(3,425)		(34,314)
Gross property and equipment	[11],[12]	366,858		257,073		366,858		257,073
Eliminations
Segment Reporting Information [Line Items]
Oil, NGL and natural gas sales		0		(346)		0		(551)
Midstream service revenues		(9,506)		(2,636)		(18,972)		(5,010)
Sales of purchased oil		0		0		0		0
Total revenues		(9,506)		(2,982)		(18,972)		(5,561)
Lease operating expenses, including production tax		(2,586)		(2,717)		(4,997)		(5,096)
Midstream service expenses		(5,394)		(221)		(11,294)		(333)
Costs of purchased oil		0		0		0		0
General and administrative		0	[1]	0	[1]	0	[2]	0	[2]
Depletion, depreciation and amortization		0	[3]	0	[3]	0	[4]	0	[4]
Impairment expense		0		0		0		0
Other operating costs and expenses		0	[5]	0	[5]	0	[6]	0	[6]
Operating income (loss)		(1,526)		(44)		(2,681)		(132)
Income from equity method investee		0		0		0		0
Interest expense		0	[7]	0	[7]	0	[8]	0	[8]
Loss on early redemption of debt				0	[9]			0	[10]
Capital expenditures		0		0		0		0
Gross property and equipment	[11],[12]	$ (4,604)		$ (365)		$ (4,604)		$ (365)

[1] General and administrative expense was allocated based on the number of employees in the respective segment as of June 30, 2016 and 2015. Certain components of general and administrative expense, primarily payroll, deferred compensation and vehicle expenses, were not allocated but were actual expenses for each segment. Land and geology expenses were not allocated to the midstream and marketing segment.

[2] General and administrative expense was allocated based on the number of employees in the respective segment as of June 30, 2016 and 2015. Certain components of general and administrative expense, primarily payroll, deferred compensation and vehicle expenses, were not allocated but were actual expenses for each segment. Land and geology expenses were not allocated to the midstream and marketing segment.

[3] Depletion, depreciation and amortization were actual expenses for each segment with the exception of the allocation of depreciation of other fixed assets, which is based on the number of employees in the respective segment as of June 30, 2016 and 2015.

[4] Depletion, depreciation and amortization were actual expenses for each segment with the exception of the allocation of depreciation of other fixed assets, which is based on the number of employees in the respective segment as of June 30, 2016 and 2015.

[5] Other operating costs and expenses consist of accretion of asset retirement obligations. These are actual costs and expenses and were not allocated.

[6] Other operating costs and expenses consist of accretion of asset retirement obligations for the six months ended June 30, 2016 and 2015 and restructuring expense for the six months ended June 30, 2015. These are actual costs and expenses and were not allocated.

[7] Interest expense was allocated to the exploration and production segment based on gross property and equipment as of June 30, 2016 and 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of June 30, 2016 and 2015.

[8] Interest expense was allocated to the exploration and production segment based on gross property and equipment as of June 30, 2016 and 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of June 30, 2016 and 2015.

[9] Loss on early redemption of debt was allocated to the exploration and production segment based on gross property and equipment as of June 30, 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of June 30, 2015.

[10] Loss on early redemption of debt was allocated to the exploration and production segment based on gross property and equipment as of June 30, 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of June 30, 2015.

[11] Gross property and equipment for the midstream and marketing segment includes investment in equity method investee totaling $213.6 million and $103.2 million as of June 30, 2016 and 2015, respectively. Other fixed assets were allocated based on the number of employees in the respective segment as of June 30, 2016 and 2015.

[12] Gross property and equipment for the midstream and marketing segment includes investment in equity method investee totaling $213.6 million and $103.2 million as of June 30, 2016 and 2015, respectively. Other fixed assets were allocated based on the number of employees in the respective segment as of June 30, 2016 and 2015.

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Segments - Additional Information (Details) $ in Thousands	6 Months Ended
	Jun. 30, 2016 USD ($) segment	Dec. 31, 2015 USD ($)	Jun. 30, 2015 USD ($)
Segment Reporting [Abstract]
Number of operating segments | segment	2
Investment in equity method investee | $	$ 213,616	$ 192,524	$ 103,200

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Subsidiary guarantors - Condensed consolidating balance sheet (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Subsidiary guarantees
Accounts receivable, net	$ 88,543	$ 87,699
Other current assets	122,719	244,533
Total oil and natural gas properties, net	975,176	1,024,992
Total midstream service assets, net	128,052	131,725
Total other fixed assets, net	40,951	43,538
Investment in subsidiaries and equity method investee	213,616	192,524
Total other long-term assets	41,094	88,276
Total assets	1,610,151	1,813,287
Accounts payable	14,500	14,181
Other current liabilities	139,312	202,634
Long-term debt, net	1,392,877	1,416,226
Other long-term liabilities	54,300	48,799
Stockholders' equity	9,162	131,447
Total liabilities and stockholders’ equity	1,610,151	1,813,287
Intercompany eliminations
Subsidiary guarantees
Accounts receivable, net	0	0
Other current assets	0	0
Total oil and natural gas properties, net	(4,604)	(1,923)
Total midstream service assets, net	0	0
Total other fixed assets, net	0	0
Investment in subsidiaries and equity method investee	(348,623)	(301,891)
Total other long-term assets	0	0
Total assets	(353,227)	(303,814)
Accounts payable	0	0
Other current liabilities	0	0
Long-term debt, net	0	0
Other long-term liabilities	0	0
Stockholders' equity	(353,227)	(303,814)
Total liabilities and stockholders’ equity	(353,227)	(303,814)
Laredo | Reportable Legal Entities
Subsidiary guarantees
Accounts receivable, net	73,429	74,613
Other current assets	120,982	244,477
Total oil and natural gas properties, net	970,445	1,017,565
Total midstream service assets, net	0	0
Total other fixed assets, net	40,701	43,210
Investment in subsidiaries and equity method investee	348,623	301,891
Total other long-term assets	37,526	84,360
Total assets	1,591,706	1,766,116
Accounts payable	12,934	12,203
Other current liabilities	120,756	158,283
Long-term debt, net	1,392,877	1,416,226
Other long-term liabilities	51,373	46,034
Stockholders' equity	13,766	133,370
Total liabilities and stockholders’ equity	1,591,706	1,766,116
Subsidiary Guarantors | Reportable Legal Entities
Subsidiary guarantees
Accounts receivable, net	15,114	13,086
Other current assets	1,737	56
Total oil and natural gas properties, net	9,335	9,350
Total midstream service assets, net	128,052	131,725
Total other fixed assets, net	250	328
Investment in subsidiaries and equity method investee	213,616	192,524
Total other long-term assets	3,568	3,916
Total assets	371,672	350,985
Accounts payable	1,566	1,978
Other current liabilities	18,556	44,351
Long-term debt, net	0	0
Other long-term liabilities	2,927	2,765
Stockholders' equity	348,623	301,891
Total liabilities and stockholders’ equity	$ 371,672	$ 350,985

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Subsidiary guarantors - Condensed consolidating statement of operations (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Subsidiary guarantees
Total revenues	$ 146,773	$ 182,331	$ 253,330	$ 333,025
Total costs and expenses	128,899	683,811	412,244	861,003
Operating income (loss)	17,874	(501,480)	(158,914)	(527,978)
Interest expense and other, net	(23,501)	(23,797)	(47,107)	(56,088)
Other non-operating income (expense)	(65,805)	(93,603)	(45,782)	(31,643)
Loss before income taxes	(71,432)	(618,880)	(251,803)	(615,709)
Deferred income tax (expense) benefit	0	221,846	0	218,203
Net loss	(71,432)	(397,034)	(251,803)	(397,506)
Intercompany eliminations
Subsidiary guarantees
Total revenues	(9,506)	(2,982)	(18,972)	(5,561)
Total costs and expenses	(7,980)	(2,938)	(16,291)	(5,429)
Operating income (loss)	(1,526)	(44)	(2,681)	(132)
Interest expense and other, net	0	0	0	0
Other non-operating income (expense)	(4,718)	(5,150)	(8,318)	(3,469)
Loss before income taxes	(6,244)	(5,194)	(10,999)	(3,601)
Deferred income tax (expense) benefit	0	0	0	0
Net loss	(6,244)	(5,194)	(10,999)	(3,601)
Laredo | Reportable Legal Entities
Subsidiary guarantees
Total revenues	102,511	125,687	175,633	243,833
Total costs and expenses	84,137	629,359	334,201	772,667
Operating income (loss)	18,374	(503,672)	(158,568)	(528,834)
Interest expense and other, net	(23,501)	(23,797)	(47,107)	(56,088)
Other non-operating income (expense)	(64,779)	(91,367)	(43,447)	(30,655)
Loss before income taxes	(69,906)	(618,836)	(249,122)	(615,577)
Deferred income tax (expense) benefit	0	221,846	0	218,203
Net loss	(69,906)	(396,990)	(249,122)	(397,374)
Subsidiary Guarantors | Reportable Legal Entities
Subsidiary guarantees
Total revenues	53,768	59,626	96,669	94,753
Total costs and expenses	52,742	57,390	94,334	93,765
Operating income (loss)	1,026	2,236	2,335	988
Interest expense and other, net	0	0	0	0
Other non-operating income (expense)	3,692	2,914	5,983	2,481
Loss before income taxes	4,718	5,150	8,318	3,469
Deferred income tax (expense) benefit	0	0	0	0
Net loss	$ 4,718	$ 5,150	$ 8,318	$ 3,469

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Subsidiary guarantors - Condensed consolidating statement of cash flows (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Subsidiary guarantees
Net cash flows provided by operating activities	$ 138,631	$ 114,305
Change in investment between affiliates	0	0
Capital expenditures and other	(243,630)	(429,646)
Net cash flows provided by financing activities	93,154	343,613
Net (decrease) increase in cash and cash equivalents	(11,845)	28,272
Cash and cash equivalents at beginning of period	31,154	29,321
Cash and cash equivalents at end of period	19,309	57,593
Intercompany eliminations
Subsidiary guarantees
Net cash flows provided by operating activities	(8,318)	(3,469)
Change in investment between affiliates	8,318	3,469
Capital expenditures and other	0	0
Net cash flows provided by financing activities	0	0
Net (decrease) increase in cash and cash equivalents	0	0
Cash and cash equivalents at beginning of period	0	0
Cash and cash equivalents at end of period	0	0
Laredo | Reportable Legal Entities
Subsidiary guarantees
Net cash flows provided by operating activities	139,610	136,092
Change in investment between affiliates	(47,069)	(70,472)
Capital expenditures and other	(197,540)	(380,961)
Net cash flows provided by financing activities	93,154	343,613
Net (decrease) increase in cash and cash equivalents	(11,845)	28,272
Cash and cash equivalents at beginning of period	31,153	29,320
Cash and cash equivalents at end of period	19,308	57,592
Subsidiary Guarantors | Reportable Legal Entities
Subsidiary guarantees
Net cash flows provided by operating activities	7,339	(18,318)
Change in investment between affiliates	38,751	67,003
Capital expenditures and other	(46,090)	(48,685)
Net cash flows provided by financing activities	0	0
Net (decrease) increase in cash and cash equivalents	0	0
Cash and cash equivalents at beginning of period	1	1
Cash and cash equivalents at end of period	$ 1	$ 1

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Subsequent Events (Details)									1 Months Ended	3 Months Ended	6 Months Ended
	Aug. 09, 2016 USD ($) shares	Jul. 29, 2016 USD ($)	Jul. 19, 2016 USD ($) shares	Jul. 18, 2016 USD ($)	Jul. 13, 2016 USD ($)	Jul. 12, 2016 USD ($)	May 16, 2016 USD ($) shares	Mar. 05, 2015 USD ($) shares	Aug. 04, 2016 a bbl	Dec. 31, 2016 USD ($)	Jun. 30, 2016 USD ($)	Jun. 30, 2015 USD ($)
Subsequent Event [Line Items]
Investment in equity method investee											$ 42,681,000	$ 14,495,000
Proceeds from issuance of common stock, net of offering costs							$ 119,300,000	$ 754,200,000			$ 119,310,000	$ 754,163,000
Subsequent Event | Leasehold Interests Acquired In Western Glasscock And Reagan Counties [Member]
Subsequent Event [Line Items]
Area of land (in acres) | a									9,200
Number Of Barrels Of Oil Produced | bbl									300
Subsequent Event | Leasehold Interests
Subsequent Event [Line Items]
Payments				$ 1,650,000	$ 92,700,000
Subsequent Event | Senior Secured Credit Facility
Subsequent Event [Line Items]
Amount borrowed						$ 94,700,000.0
Outstanding amount			$ 70,000,000			$ 205,000,000
Subsequent Event | Medallion Gathering And Processing LLC
Subsequent Event [Line Items]
Investment in equity method investee		$ 16,000,000
Common Stock
Subsequent Event [Line Items]
Equity issuance, net of offering costs (in shares) | shares							10,925,000	69,000,000
Common Stock | Subsequent Event
Subsequent Event [Line Items]
Equity issuance, net of offering costs (in shares) | shares			13,000,000
Proceeds from issuance of common stock, net of offering costs			$ 136,300,000
Stock authorized for purchase | shares			1,950,000
Scenario, Forecast | Subsequent Event | Leasehold Interests
Subsequent Event [Line Items]
Payments										$ 125,000,000
Scenario, Forecast | Common Stock | Subsequent Event
Subsequent Event [Line Items]
Equity issuance, net of offering costs (in shares) | shares	1,950,000
Proceeds from issuance of common stock, net of offering costs	$ 20,500,000

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Subsequent events - New Commodity Derivatives Contract (Details) - January 2017 - December 2017 - Swaps - Subsequent Event	Aug. 04, 2016 bbl $ / bbl
Crude Oil
Subsequent Event [Line Items]
Aggregate volumes (Bbl) | bbl	1,003,750	[1]
Floor price | $ / bbl	51.90	[1]
Natural Gas Liquids
Subsequent Event [Line Items]
Aggregate volumes (Bbl) | bbl	444,000	[2]
Floor price | $ / bbl	11.24	[2]
Crude Oil
Subsequent Event [Line Items]
Aggregate volumes (Bbl) | bbl	1,003,750	[1]
Floor price | $ / bbl	51.17	[1]
Natural Gas Liquids
Subsequent Event [Line Items]
Aggregate volumes (Bbl) | bbl	375,000	[3]
Floor price | $ / bbl	22.26	[3]

[1] The associated derivatives will be settled based on the WTI NYMEX index oil price.

[2] The associated derivative will be settled based on the Mont Belvieu Purity Ethane-OPIS price.

[3] The associated derivative will be settled based on the Mont Belvieu Propane (TET)-OPIS price.

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Supplementary information (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Property acquisition costs:
Evaluated		$ 0	$ 0	$ 0	$ 0
Unevaluated		0	0	0	0
Exploration		19,769	3,841	27,032	8,354
Development costs	[1]	70,806	110,518	152,692	317,190
Total costs incurred		90,575	114,359	179,724	325,544
Asset Retirement Obligations
Property acquisition costs:
Total costs incurred		$ 100	$ 500	$ 200	$ 1,000

[1] (1)The costs incurred for oil, NGL and natural gas development activities include $0.1 million and $0.5 million in asset retirement obligations for the three months ended June 30, 2016 and 2015, respectively, and $0.2 million and $1.0 million for the six months ended June 30, 2016 and 2015, respectively.