Edgar Filing: Laredo Petroleum, Inc.

Document

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, 2017

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 website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No o

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



Large accelerated filer ý		Accelerated filer o

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

Emerging growth company o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

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

Number of shares of registrant's common stock outstanding as of August 3, 2017: 242,505,312

LAREDO PETROLEUM, INC.

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		Page
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS		iii
	Part I
Item 1.	Consolidated Financial Statements (Unaudited):
	Consolidated balance sheets as of June 30, 2017 and December 31, 2016	1
	Consolidated statements of operations for the three and six months ended June 30, 2017 and 2016	2
	Consolidated statement of stockholders' equity for the six months ended June 30, 2017	3
	Consolidated statements of cash flows for the six months ended June 30, 2017 and 2016	4
	Condensed notes to the consolidated financial statements:
	Note 1—Organization	5
	Note 2—Basis of presentation and significant accounting policies	5
	Note 3—Divestiture	11
	Note 4—Debt	11
	Note 5—Employee compensation	13
	Note 6—Income taxes	17
	Note 7—Derivatives	17
	Note 8—Fair value measurements	21
	Note 9—Net income (loss) per common share	25
	Note 10—Credit risk	25
	Note 11—Commitments and contingencies	26
	Note 12—Related parties	27
	Note 13—Segments	27
	Note 14—Subsidiary guarantors	30
	Note 15—Recently issued or adopted accounting pronouncements	33
	Note 16—Subsequent events	34
	Note 17—Supplementary information	35
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	36
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	51
Item 4.	Controls and Procedures	53
	Part II
Item 1.	Legal Proceedings	54
Item 1A.	Risk Factors	54
Item 2.	Repurchase of Equity Securities	54
Item 3.	Defaults Upon Senior Securities	54
Item 4.	Mine Safety Disclosures	54
Item 5.	Other Information	54
Item 6.	Exhibits	56
SIGNATURES		57
EXHIBIT INDEX		58

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in or incorporated by reference into this Quarterly Report on Form 10-Q (this "Quarterly Report") are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). These forward-looking statements include statements, projections and estimates concerning our operations, performance, business strategy, oil 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 other uncertainties;


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


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


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


•	the 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;


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


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


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


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


•	our ability to execute our strategies;


•	competition in the oil and natural gas industry;


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


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


•	risks related to the geographic concentration of our assets;


•	the availability and 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

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•	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, 2016 (the "2016 Annual Report"), and those set forth from time to time in our other filings with the Securities and Exchange Commission (the "SEC"). These documents are available through our website or through the SEC's Electronic Data Gathering and Analysis Retrieval system at http://www.sec.gov. In light of such risks and uncertainties, we caution you not to place undue reliance on these forward-looking statements. These forward-looking statements speak only as of the date of this Quarterly Report, or if earlier, as of the date they were made. We do not intend to, and disclaim any obligation to, update or revise any forward-looking statements unless required by securities law.

Table of Contents

Part I

Item 1. Consolidated Financial Statements (Unaudited)

Laredo Petroleum, Inc.

Consolidated balance sheets

(in thousands, except share data)

(Unaudited)



	June 30, 2017			December 31, 2016
Assets
Current assets:
Cash and cash equivalents	$	35,024		$	32,672
Accounts receivable, net	72,107			86,867
Derivatives	42,985			20,947
Other current assets	17,548			14,291
Total current assets	167,664			154,777
Property and equipment:
Oil and natural gas properties, full cost method:
Evaluated properties	5,703,873			5,488,756
Unevaluated properties not being depleted	203,888			221,281
Less accumulated depletion and impairment	(4,578,831		)	(4,514,183		)
Oil and natural gas properties, net	1,328,930			1,195,854
Midstream service assets, net	128,941			126,240
Other fixed assets, net	41,415			44,773
Property and equipment, net	1,499,286			1,366,867
Derivatives	12,807			8,718
Investment in equity method investee	249,492			243,953
Other assets, net	12,005			8,031
Total assets	$	1,941,254		$	1,782,346
Liabilities and stockholders' equity
Current liabilities:
Accounts payable	$	10,777		$	15,054
Undistributed revenue and royalties	32,166			26,838
Accrued capital expenditures	53,700			30,845
Derivatives	653			20,993
Other current liabilities	74,787			94,215
Total current liabilities	172,083			187,945
Long-term debt, net	1,390,277			1,353,909
Derivatives	—			5,694
Asset retirement obligations	51,034			50,604
Other noncurrent liabilities	3,457			3,621
Total liabilities	1,616,851			1,601,773
Commitments and contingencies
Stockholders' equity:
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued as of June 30, 2017 and December 31, 2016	—			—
Common stock, $0.01 par value, 450,000,000 shares authorized and 242,534,185 and 241,929,070 issued and outstanding as of June 30, 2017 and December 31, 2016, respectively	2,425			2,419
Additional paid-in capital	2,410,674			2,396,236
Accumulated deficit	(2,088,696		)	(2,218,082		)
Total stockholders' equity	324,403			180,573
Total liabilities and stockholders' equity	$	1,941,254		$	1,782,346

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

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Laredo Petroleum, Inc.

Consolidated statements of operations

(in thousands, except per share data)

(Unaudited)



	Three months ended June 30,						Six months ended June 30,
	2017			2016			2017			2016
Revenues:
Oil, NGL and natural gas sales	$	141,837		$	102,526		$	280,573		$	175,668
Midstream service revenues	2,703			1,632			5,702			3,433
Sales of purchased oil	42,461			42,615			89,732			74,229
Total revenues	187,001			146,773			376,007			253,330
Costs and expenses:
Lease operating expenses	20,104			19,225			37,096			39,743
Production and ad valorem taxes	8,472			7,982			17,253			14,417
Midstream service expenses	896			1,178			1,812			1,787
Costs of purchased oil	44,020			44,012			94,276			76,958
General and administrative	22,008			20,502			47,605			39,953
Depletion, depreciation and amortization	38,003			34,177			72,115			75,655
Impairment expense	—			963			—			162,027
Other operating expenses	1,437			860			2,463			1,704
Total costs and expenses	134,940			128,899			272,620			412,244
Operating income (loss)	52,061			17,874			103,387			(158,914		)
Non-operating income (expense):
Gain (loss) on derivatives, net	28,897			(68,518		)	65,568			(50,633		)
Income from equity method investee	2,471			3,696			5,539			5,994
Interest expense	(23,173		)	(23,512		)	(45,893		)	(47,217		)
Interest and other income	49			11			194			110
Write-off of debt issuance costs	—			(842		)	—			(842		)
Gain (loss) on disposal of assets, net	805			(141		)	591			(301		)
Non-operating income (expense), net	9,049			(89,306		)	25,999			(92,889		)
Income (loss) before income taxes	61,110			(71,432		)	129,386			(251,803		)
Income tax:
Deferred	—			—			—			—
Total income tax	—			—			—			—
Net income (loss)	$	61,110		$	(71,432	)	$	129,386		$	(251,803	)
Net income (loss) per common share:
Basic	$	0.26		$	(0.33	)	$	0.54		$	(1.17	)
Diluted	$	0.25		$	(0.33	)	$	0.53		$	(1.17	)
Weighted-average common shares outstanding:
Basic	239,231			217,564			238,870			214,562
Diluted	244,417			217,564			244,385			214,562

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

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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			Additional paid-in capital			Shares		Amount			Accumulated deficit			Total
Balance, December 31, 2016	241,929		$	2,419		$	2,396,236		—		$	—		$	(2,218,082	)	$	180,573
Restricted stock awards	1,185		12			(12		)	—		—			—			—
Restricted stock forfeitures	(232	)	(2		)	2			—		—			—			—
Performance share conversion	150		2			(2		)	—		—			—			—
Vested stock exchanged for tax withholding	—		—			—			542		(7,597		)	—			(7,597		)
Retirement of treasury stock	(542	)	(6		)	(7,591		)	(542	)	7,597			—			—
Exercise of stock options	44		—			358			—		—			—			358
Stock-based compensation	—		—			21,683			—		—			—			21,683
Net income	—		—			—			—		—			129,386			129,386
Balance, June 30, 2017	242,534		$	2,425		$	2,410,674		—		$	—		$	(2,088,696	)	$	324,403

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

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Laredo Petroleum, Inc.

Consolidated statements of cash flows

(in thousands)

(Unaudited)



	Six months ended June 30,
	2017			2016
Cash flows from operating activities:
Net income (loss)	$	129,386		$	(251,803	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization	72,115			75,655
Impairment expense	—			162,027
Non-cash stock-based compensation, net of amounts capitalized	17,911			9,911
Mark-to-market on derivatives:
(Gain) loss on derivatives, net	(65,568		)	50,633
Cash settlements received for matured derivatives, net	21,156			113,319
Cash settlements received for early terminations of derivatives, net	4,234			80,000
Change in net present value of derivative deferred premiums	111			133
Cash premiums paid for derivatives	(12,094		)	(84,263		)
Amortization of debt issuance costs	2,094			2,187
Write-off of debt issuance costs	—			842
Income from equity method investee	(5,539		)	(5,994		)
Cash settlement of performance unit awards	—			(6,394		)
Other, net	1,414			2,009
Decrease (increase) in accounts receivable	14,760			(844		)
Increase in other assets	(3,516		)	(117		)
(Decrease) increase in accounts payable	(4,277		)	319
Increase (decrease) in undistributed revenues and royalties	5,328			(9,088		)
(Decrease) increase in other accrued liabilities	(20,449		)	295
Decrease in other noncurrent liabilities	(165		)	(196		)
Net cash provided by operating activities	156,901			138,631
Cash flows from investing activities:
Capital expenditures:
Oil and natural gas properties	(232,219		)	(197,042		)
Midstream service assets	(6,117		)	(3,425		)
Other fixed assets	(2,683		)	(832		)
Investment in equity method investee	—			(42,681		)
Proceeds from dispositions of capital assets, net of selling costs	63,441			350
Net cash used in investing activities	(177,578		)	(243,630		)
Cash flows from financing activities:
Borrowings on Senior Secured Credit Facility	90,000			120,000
Payments on Senior Secured Credit Facility	(55,000		)	(144,682		)
Proceeds from issuance of common stock, net of offering costs	—			119,310
Purchase of treasury stock	(7,597		)	(1,541		)
Proceeds from exercise of employee stock options	358			67
Payments for debt issuance costs	(4,732		)	—
Net cash provided by financing activities	23,029			93,154
Net increase (decrease) in cash and cash equivalents	2,352			(11,845		)
Cash and cash equivalents, beginning of period	32,672			31,154
Cash and cash equivalents, end of period	$	35,024		$	19,309

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



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Note 1—Organization

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

LMS holds 49% of the ownership units of Medallion Gathering & Processing, LLC, a Texas limited liability company formed on October 12, 2012, which, together with its wholly-owned subsidiaries (collectively, "Medallion"), is focused on developing midstream solutions and providing midstream infrastructure in the Midland Basin. The Company accounts for Medallion as an equity method investment.

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

Note 2—Basis of presentation and significant accounting policies

a. Basis of presentation

The accompanying unaudited consolidated financial statements were derived from the historical accounting records of the Company and reflect the historical financial position, results of operations and cash flows for the periods described herein. The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). All material intercompany transactions and account balances have been eliminated in the consolidation of accounts. The Company uses the equity method of accounting to record its net interests when the Company holds 20% to 50% of the voting rights and/or has the ability to exercise significant influence but does not control the entity. Under the equity method, the Company's proportionate share of the investee's net income is included in the unaudited consolidated statements of operations. See Note 2.h for additional discussion of the Company's equity method investment.

The 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, 2016 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, 2017, results of operations for the three and six months ended June 30, 2017 and 2016 and cash flows for the six months ended June 30, 2017 and 2016.

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 2016 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) impairments, (v) asset retirement obligations, (vi) stock-based compensation, (vii) deferred income taxes, (viii) fair value of assets acquired and liabilities assumed in an acquisition, (ix) fair value of derivatives and deferred premiums and (x) contingent liabilities. As fair value is a market-based measurement, it is determined based on the assumptions that would be used by market participants.



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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 2017 presentation. These reclassifications had no impact to previously reported balance sheets or stockholders' equity.

d. Accounts receivable

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

The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses, current receivables aging and existing industry and economic data. The Company reviews its allowance for doubtful accounts quarterly. Past due amounts greater than 90 days and greater than a specified amount are reviewed individually for collectability. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is remote.

Accounts receivable consisted of the following components as of the dates presented:



(in thousands)	June 30, 2017		December 31, 2016
Oil, NGL and natural gas sales	$	45,495	$	46,999
Sales of purchased oil and other products	11,518		16,213
Joint operations, net⁽¹⁾	8,973		12,175
Matured derivatives	5,982		11,059
Other	139		421
Total	$	72,107	$	86,867

______________________________________________________________________________


(1)	Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.1 million and $0.2 million as of June 30, 2017 and December 31, 2016, respectively. As the operator of the majority of its wells, the Company has the ability to realize some or all of these receivables through the netting of production revenues.

e. Derivatives

The Company uses derivatives to reduce exposure to fluctuations in the 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 call spreads.

Derivatives are recorded at fair value and are presented on a net basis on the unaudited consolidated balance sheets as assets and/or liabilities. The Company nets the fair value of derivatives by counterparty where the right of offset exists. The Company determines the fair value of its derivatives by utilizing pricing models for substantially similar instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. See Note 8.a for discussion regarding the fair value of the Company's derivatives.

The Company's derivatives were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the unaudited consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities. See Notes 7 and 8.a for discussion regarding the Company's derivatives.



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

f. Other current assets and liabilities

Other current assets consisted of the following components as of the dates presented:



(in thousands)	June 30, 2017		December 31, 2016
Prepaid expenses and other	$	8,958	$	6,228
Inventory⁽¹⁾	8,590		8,063
Total other current assets	$	17,548	$	14,291

______________________________________________________________________________


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

Other current liabilities consisted of the following components as of the dates presented:



(in thousands)	June 30, 2017		December 31, 2016
Accrued interest payable	$	24,354	$	24,152
Purchased oil payable	11,971		17,213
Accrued compensation and benefits	9,122		25,947
Lease operating expense payable	8,814		10,572
Other accrued liabilities	20,526		16,331
Total other current liabilities	$	74,787	$	94,215

g. Property and equipment

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



(in thousands)	June 30, 2017			December 31, 2016
Evaluated oil and natural gas properties	$	5,703,873		$	5,488,756
Less accumulated depletion and impairment	(4,578,831		)	(4,514,183		)
Evaluated oil and natural gas properties, net	1,125,042			974,573

Unevaluated properties not being depleted	203,888			221,281

Midstream service assets	157,645			150,629
Less accumulated depreciation and impairment	(28,704		)	(24,389		)
Midstream service assets, net	128,941			126,240

Depreciable other fixed assets	48,997			52,491
Less accumulated depreciation and amortization	(22,496		)	(22,632		)
Depreciable other fixed assets, net	26,501			29,859

Land	14,914			14,914

Total property and equipment, net	$	1,499,286		$	1,366,867

For the three months ended June 30, 2017 and 2016, depletion expense was $6.44 per barrel of oil equivalent ("BOE") sold and $7.06 per BOE sold, respectively. For the six months ended June 30, 2017 and 2016, depletion expense was $6.44 per BOE sold and $8.01 per BOE sold, respectively.

The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain related employee costs, incurred for the purpose of exploring for or developing oil and natural gas properties, are capitalized and depleted on a composite unit of production method based on proved oil, NGL and natural gas reserves. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Costs, including related employee costs, associated with production and general corporate activities are expensed in the period incurred. Sales of oil and natural gas



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Condensed notes to the consolidated financial statements

(Unaudited)

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

The following table presents capitalized employee-related costs for the periods presented:



	Three months ended June 30,				Six months ended June 30,
(in thousands)	2017		2016		2017		2016
Capitalized employee-related costs	$	5,763	$	3,253	$	10,973	$	6,449

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

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

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

Full cost ceiling impairment expense for the six months ended June 30, 2016 was $161.1 million and is included in the "Impairment expense" line item in the unaudited consolidated statements of operations and in the financial information provided for the Company's exploration and production segment presented in Note 13. There were no full cost ceiling impairments recorded during the six months ended June 30, 2017.

h. Variable interest entity

Medallion was established for the purpose of developing midstream solutions and providing midstream infrastructure to bring oil to market in the Midland Basin. LMS holds 49% of Medallion's ownership units. LMS and the third-party 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 many key operating and business decisions. The Company has determined that Medallion is a variable interest entity ("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. The Company's proportionate share of Medallion's net income is reflected in the unaudited consolidated statements of operations as "Income from equity method investee" and the carrying amount is reflected in the unaudited consolidated balance sheets as "Investment in equity method investee." The Company has elected to classify distributions received from Medallion using the cumulative earnings approach. No such distributions have been received through June 30, 2017.

LMS contributed $16.0 million and $42.7 million during the three and six months ended June 30, 2016, respectively, to Medallion. There were no contributions to Medallion during the six months ended June 30, 2017. Medallion continued expansion activities on existing portions of its pipeline infrastructure in order to gather and transport additional third-party oil production during each of the six months ended June 30, 2017 and 2016. See Note 12.a for discussion of items included in the Company's unaudited consolidated financial statements related to Medallion. See Note 16.b for discussion regarding a capital call received from Medallion subsequent to June 30, 2017.



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Condensed notes to the consolidated financial statements

(Unaudited)

The third-party 51% interest-holder has initiated a process to potentially sell 100% of the ownership interests in Medallion within the next 12 months.

i. Long-lived assets and inventory

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

Materials and supplies inventory, which is used in the Company's production activities of oil and natural gas properties and midstream service assets, is carried at the lower of cost or net realizable value ("NRV"), with cost determined using the weighted-average cost method, and is included in "Other current assets" and "Other assets, net" on the unaudited consolidated balance sheets. The NRV for materials and supplies inventory is determined utilizing a replacement cost approach (Level 2).

The Company has frac pit water inventory, which is used in developing oil and natural gas properties and is carried at lower of cost or NRV, with cost determined using the weighted-average cost method, and is included in "Other current assets" on the unaudited consolidated balance sheets. The NRV for frac pit water inventory is determined utilizing a replacement cost approach (Level 2).

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

There were no long-lived assets impairments recorded during the six months ended June 30, 2017 or 2016. Inventory impairments of $1.0 million were recorded for each of the three and six months ended June 30, 2016. There were no inventory impairments recorded during the six months ended June 30, 2017.

j. Debt issuance costs

Debt issuance fees, which are recorded at cost, net of amortization, are amortized over the life of the respective debt agreements utilizing the effective interest and straight-line methods. The Company capitalized $4.7 million of debt issuance costs during the six months ended June 30, 2017 as a result of entering into the Fifth Amended and Restated Credit Agreement (as amended, the "Senior Secured Credit Facility"). No debt issuance costs were capitalized during the six months ended June 30, 2016. The Company had total debt issuance costs of $21.4 million and $18.8 million, net of accumulated amortization of $23.4 million and $21.3 million, as of June 30, 2017 and December 31, 2016, respectively.

No debt issuance costs were written off during the six months ended June 30, 2017. The Company wrote-off $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. Debt issuance costs related to the Company's senior unsecured notes are presented in "Long-term debt, net" on the Company's unaudited consolidated balance sheets. Debt issuance costs related to the Senior Secured Credit Facility are presented in "Other assets, net" on the Company's unaudited consolidated balance sheets. See Note 4.f for additional discussion of debt issuance costs.

Future amortization expense of debt issuance costs as of June 30, 2017 for the periods presented is as follows:



(in thousands)	June 30, 2017
Remaining 2017	$	2,082
2018	4,223
2019	4,308
2020	4,396
2021	4,493
Thereafter	1,947
Total	$	21,449

k. Asset retirement obligations

Asset retirement obligations associated with the retirement of tangible long-lived assets are recognized as a liability in the period in which they are incurred and become determinable. The associated asset retirement costs are part of the carrying



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Condensed notes to the consolidated financial statements

(Unaudited)

amount of the long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related long-lived asset is charged to expense through depletion, or for midstream service assets through depreciation, of the associated asset. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and as corresponding accretion expense.

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

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

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



(in thousands)	Six months ended June 30, 2017			Year ended December 31, 2016
Liability at beginning of period	$	52,207		$	46,306
Liabilities added due to acquisitions, drilling, midstream service asset construction and other	320			1,528
Accretion expense	1,871			3,483
Liabilities settled upon plugging and abandonment	(363		)	(1,242		)
Liabilities removed due to sale of property	(871		)	—
Revision of estimates	5			2,132
Liability at end of period	$	53,169		$	52,207

l. Fair value measurements

The carrying amounts reported in the unaudited consolidated balance sheets for cash and cash equivalents, accounts receivable, accounts payable, undistributed revenue and royalties, accrued capital expenditures and other accrued assets and liabilities approximate their fair values. See Note 4.e for fair value disclosures related to the Company's debt obligations. The Company carries its derivatives at fair value. See Note 8.a for details regarding the fair value of the Company's derivatives.

m. Treasury stock

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

n. Compensation awards

Stock-based compensation expense, net of amounts capitalized, is included in "General and administrative" in the unaudited consolidated statements of operations over the awards' vesting periods and is based on the awards' grant date fair value. The Company utilizes the closing stock price on the grant date, less an expected forfeiture rate, to determine the fair values of service vesting restricted stock awards and a Black-Scholes pricing model to determine the fair values of service vesting restricted stock option awards. The Company utilizes a Monte Carlo simulation prepared by an independent third party to determine the fair values of the performance share awards and, in prior periods, the performance unit awards. The Company capitalizes a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration and development of its oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included as an addition to "Oil and natural gas properties" in the unaudited consolidated balance sheets. See Note 5 for further discussion regarding the restricted stock awards, stock option awards, performance share awards and performance unit awards.



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Condensed notes to the consolidated financial statements

(Unaudited)

o. May 2016 Equity Offering

On May 16, 2016, the Company completed the sale of 10,925,000 shares of Laredo's common stock (the "May 2016 Equity Offering") for net proceeds of $119.3 million, after underwriting discounts, commissions and offering expenses. There were no comparative offerings of Laredo's stock during the six months ended June 30, 2017.

p. Environmental

The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, among other things, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed in the period incurred. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. Management believes no materially significant liabilities of this nature existed as of June 30, 2017 or December 31, 2016.

q. Non-cash investing and supplemental cash flow information

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



	Six months ended June 30,
(in thousands)	2017		2016
Non-cash investing information:
Change in accrued capital expenditures	$	22,855	$	(22,012	)
Change in accrued capital contribution to equity method investee⁽¹⁾	$	—	$	(27,583	)
Capitalized asset retirement cost	$	325	$	253
Supplemental cash flow information:
Capitalized interest	$	490	$	115

______________________________________________________________________________


(1)	See Notes 2.h and 12.a for additional discussion of the Company's equity method investee.

Note 3—Divestiture

In January 2017, the Company completed the sale of 2,900 net acres and working interests in 16 producing vertical wells in the Midland Basin to a third-party buyer for a purchase price of $59.7 million. After transaction costs reflecting an economic effective date of October 1, 2016, the proceeds were $59.5 million, net of working capital and post-closing adjustments. The Company completed the closing adjustments for this divestiture in May 2017. A portion of these proceeds were used to pay down borrowings on the Senior Secured Credit Facility. The purchase price was recorded as an adjustment to oil and natural gas properties pursuant to the rules governing full cost accounting.

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

Note 4—Debt

a. March 2023 Notes

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



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Condensed notes to the consolidated financial statements

(Unaudited)

Notes are callable by the Company beginning March 15, 2018 at a price of 104.688% of face value with call premiums declining over time to 100% of face value on March 15, 2021 and thereafter.

b. January 2022 Notes

On January 23, 2014, the Company completed an offering of $450.0 million in aggregate principal amount of 5 5/8% senior unsecured notes due 2022 (the "January 2022 Notes"). The January 2022 Notes will mature on January 15, 2022 and bear an interest rate of 5 5/8% per annum, payable semi-annually, in cash in arrears on January 15 and July 15 of each year, commencing July 15, 2014. The January 2022 Notes are fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain Releases. The January 2022 Notes became callable by the Company on January 15, 2017 at a price of 104.219% of face value with call premiums declining over time to 100% of face value on January 15, 2020 and thereafter.

c. May 2022 Notes

On April 27, 2012, the Company completed an offering of $500.0 million in aggregate principal amount of 7 3/8% senior unsecured notes due 2022 (the "May 2022 Notes"). The May 2022 Notes will mature on May 1, 2022 and bear an interest rate of 7 3/8% per annum, payable semi-annually, in cash in arrears on May 1 and November 1 of each year, commencing November 1, 2012. The May 2022 Notes are fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain Releases. The May 2022 Notes became callable by the Company on May 1, 2017 at a price of 103.688% of face value with call premiums declining over time to 100% of face value on May 1, 2020 and thereafter.

d. Senior Secured Credit Facility

As of June 30, 2017, the Senior Secured Credit Facility, had a maximum credit amount of $2.0 billion, a borrowing base and an aggregate elected commitment each of $1.0 billion with $105.0 million outstanding and was subject to an interest rate of 3.13%. The Senior Secured Credit Facility has a maturity date of May 2, 2022, provided that if either the January 2022 Notes or May 2022 Notes have not been redeemed or refinanced on or prior to the date 90 days before their respective stated maturity dates (as applicable, the "Early Maturity Date"), the Senior Secured Credit Facility will mature on such Early Maturity Date. The Senior Secured Credit Facility contains both financial and non-financial covenants, all of which the Company was in compliance with as of June 30, 2017. Laredo is required to pay an annual commitment fee on the unused portion of the financial institutions' commitment of 0.375% to 0.5%, based on the ratio of outstanding revolving credit to the total commitment under the Senior Secured Credit Facility. 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, 2017 or 2016. See Note 16.a for discussion of an additional borrowing on the Senior Secured Credit Facility subsequent to June 30, 2017.

e. Fair value of debt

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



	June 30, 2017				December 31, 2016
(in thousands)	Long-term debt		Fair value		Long-term debt		Fair value
January 2022 Notes	$	450,000	$	440,479	$	450,000	$	456,382
May 2022 Notes	500,000		509,575		500,000		521,413
March 2023 Notes	350,000		347,351		350,000		365,649
Senior Secured Credit Facility	105,000		105,026		70,000		69,975
Total	$	1,405,000	$	1,402,431	$	1,370,000	$	1,413,419

The fair values of the debt outstanding on the January 2022 Notes, the May 2022 Notes and the March 2023 Notes were determined using the June 30, 2017 and December 31, 2016 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, 2017 and December 31, 2016 were estimated utilizing pricing models for similar instruments (Level 2). See Note 8 for information about fair value hierarchy levels.



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Condensed notes to the consolidated financial statements

(Unaudited)

f. Long-term debt, net

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



	June 30, 2017							December 31, 2016
(in thousands)	Long-term debt		Debt issuance costs, net			Long-term debt, net		Long-term debt		Debt issuance costs, net			Long-term debt, net
January 2022 Notes	$	450,000	$	(4,475	)	$	445,525	$	450,000	$	(4,963	)	$	445,037
May 2022 Notes	500,000		(5,687		)	494,313		500,000		(6,164		)	493,836
March 2023 Notes	350,000		(4,561		)	345,439		350,000		(4,964		)	345,036
Senior Secured Credit Facility⁽¹⁾	105,000		—			105,000		70,000		—			70,000
Total	$	1,405,000	$	(14,723	)	$	1,390,277	$	1,370,000	$	(16,091	)	$	1,353,909

______________________________________________________________________________


(1)	Debt issuance costs, net related to our Senior Secured Credit Facility of $6.7 million and $2.7 million as of June 30, 2017 and December 31, 2016, respectively, are reported in "Other assets, net" on the unaudited consolidated balance sheets.

Note 5—Employee compensation

The Company has a Long-Term Incentive Plan (the "LTIP"), which provides for the granting of incentive awards in the form of restricted stock awards, stock option awards, performance share awards, performance unit awards and other awards. The LTIP provides for the issuance of up to 24,350,000 shares of Laredo's common stock.

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

a. Restricted stock awards

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

The following table reflects the restricted stock award activity for the six months ended June 30, 2017:



(in thousands, except for weighted-average grant date fair values)	Restricted stock awards		Weighted-average grant date fair value (per award)
Outstanding as of December 31, 2016	3,878		$	12.88
Granted	1,185		$	13.97
Forfeited	(232	)	$	12.88
Vested⁽¹⁾	(1,588	)	$	13.75
Outstanding as of June 30, 2017	3,243		$	12.85

_____________________________________________________________________________


(1)	The total intrinsic value of vested restricted stock awards for the six months ended June 30, 2017 was $22.0 million.



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Condensed notes to the consolidated financial statements

(Unaudited)

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, 2017, unrecognized stock-based compensation related to the restricted stock awards expected to vest was $31.7 million. Such cost is expected to be recognized over a weighted-average period of 1.91 years.

b. Stock option awards

Stock option awards granted under the LTIP vest and become exercisable in four equal installments on each of the four annual anniversaries of the grant date. The following table reflects the stock option award activity for the six months ended June 30, 2017:



(in thousands, except for weighted-average price and weighted-average remaining contractual term)	Stock option awards		Weighted-average price (per option)		Weighted-average remaining contractual term (years)
Outstanding as of December 31, 2016	2,370		$	12.54	7.71
Granted	391		$	14.12
Exercised⁽¹⁾	(44	)	$	8.17
Expired or canceled	(27	)	$	21.03
Outstanding as of June 30, 2017	2,690		$	12.75	7.54
Vested and exercisable at end of period⁽²⁾	1,303		$	16.46	6.34
Expected to vest at end of period⁽³⁾	1,387		$	9.26	8.67

_____________________________________________________________________________


(1)	The total intrinsic value of exercised stock option awards for the six months ended June 30, 2017 was $0.3 million.


(2)	The vested and exercisable stock option awards as of June 30, 2017 had an aggregate intrinsic value of $1.3 million.


(3)	The stock option awards expected to vest as of June 30, 2017 had an aggregate intrinsic value of $4.4 million.

The Company utilizes the Black-Scholes option pricing model to determine the fair value of stock option awards and recognizes the associated expense on a straight-line basis over the four-year requisite service period of the awards. Determining 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, 2017, unrecognized stock-based compensation related to stock option awards expected to vest was $10.6 million. Such cost is expected to be recognized over a weighted-average period of 2.72 years.



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Condensed notes to the consolidated financial statements

(Unaudited)

The assumptions used to estimate the fair value of the 390,733 stock option awards granted during the six months ended June 30, 2017 are as follows:



	Granted on February 17, 2017
Risk-free interest rate⁽¹⁾	2.14		%
Expected option life⁽²⁾	6.25 years
Expected volatility⁽³⁾	60.84		%
Fair value per stock option award	$	8.22

____________________________________________________________________________


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


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


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

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



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

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

c. Performance share awards

Performance share awards granted to management are subject to a combination of market and service vesting criteria. A Monte Carlo simulation prepared by an independent third party is utilized to determine the grant date fair value of these awards. The Company has determined these awards are equity awards and recognizes the associated expense on a straight-line basis over the three-year requisite service period of the awards. Any shares earned under such awards are expected to be issued in the first quarter following the completion of the requisite service period based on the achievement of certain performance criteria.



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Condensed notes to the consolidated financial statements

(Unaudited)

The following table reflects the performance share award activity for the six months ended June 30, 2017:



(in thousands, except for weighted-average grant date fair values)	Performance share awards		Weighted-average grant date fair value (per award)
Outstanding as of December 31, 2016	2,325		$	18.35
Granted	696		$	18.96
Forfeited	(60	)	$	18.11
Vested⁽¹⁾	(200	)	$	28.56
Outstanding as of June 30, 2017	2,761		$	17.77

______________________________________________________________________________


(1)	These performance share awards had a performance period of January 1, 2014 to December 31, 2016 and, as their vesting and performance criteria were satisfied, each award converted into 0.75 shares representing 150,388 shares of common stock issued during the first quarter of 2017.

As of June 30, 2017, unrecognized stock-based compensation related to the performance share awards expected to vest was $29.4 million. Such cost is expected to be recognized over a weighted-average period of 1.99 years.

The assumptions used to estimate the fair values of the 696,460 performance share awards granted during the six months ended June 30, 2017 are as follows:



	Granted on February 17, 2017
Risk-free rate⁽¹⁾	1.44		%
Dividend yield	—		%
Expected volatility⁽²⁾	74.00		%
Laredo stock closing price on grant date	$	14.12
Fair value per performance share	$	18.96

______________________________________________________________________________


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


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

d. Stock-based compensation expense

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



	Three months ended June 30,						Six months ended June 30,
(in thousands)	2017			2016			2017			2016
Restricted stock award compensation	$	5,267		$	4,692		$	11,434		$	8,460
Stock option award compensation	1,144			777			2,441			1,401
Performance share award compensation	4,068			1,593			7,808			1,821
Total stock-based compensation, gross	10,479			7,062			21,683			11,682
Less amounts capitalized in oil and natural gas properties	(1,792		)	(989		)	(3,772		)	(1,771		)
Total stock-based compensation, net of amounts capitalized	$	8,687		$	6,073		$	17,911		$	9,911

e. Performance unit awards

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

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



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Condensed notes to the consolidated financial statements

(Unaudited)

Note 6—Income taxes

The Company is subject to federal and state income taxes and the Texas franchise tax. The Company had federal net operating loss carry-forwards totaling $1.7 billion and state of Oklahoma net operating loss carry-forwards totaling $42.5 million as of June 30, 2017. These carry-forwards begin expiring in 2026. As of June 30, 2017, the Company believes a portion of the net operating loss carry-forwards are not fully realizable. The Company considered all available evidence, both positive and negative, in determining whether, based on the weight of that evidence, a valuation allowance was needed. Such consideration included projected future cash flows from its oil, NGL and natural gas reserves (including the timing of those cash flows), the reversal of deferred tax liabilities recorded as of June 30, 2017, the Company's ability to capitalize intangible drilling costs, rather than expensing these costs in order to prevent an operating loss carry-forward from expiring unused, and future projections of Oklahoma sourced income. As of June 30, 2017, a full valuation allowance of $716.2 million has been recorded against the Company's deferred tax position.

Note 7—Derivatives

a. Derivatives

The Company engages in derivative transactions such as puts, swaps, collars and call spreads to hedge price risks due to unfavorable changes in oil, NGL and natural gas prices related to its production. As of June 30, 2017, the Company had 29 open derivative contracts with financial institutions that extend from July 2017 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 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 paid at inception or deferred until settlement, to enter into the put transaction. When the settlement price is below the floor price, the counterparty pays the Company an amount equal to the difference between the settlement price and the floor price multiplied by the hedged contract volume. When the settlement price is at or above the floor price in an individual month in the contract period, the put option expires with no settlement for that particular month, except with regard to the deferred premium if any.

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

Each collar transaction has an established price floor and ceiling. Depending on the terms, the Company may pay its counterparty a premium, which can be paid at inception or deferred until settlement. When the settlement price is below the price floor established by these collars, the counterparty pays the Company an amount equal to the difference between the settlement price and the price floor multiplied by the hedged contract volume. When the settlement price is above the price ceiling established by these collars, the Company pays its counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the hedged contract volume. When the settlement price is between the price floor and price ceiling established by these collars in an individual month in the contract period, the collar expires with no settlement paid by either the Company or the counterparty for that particular month, except with regard to the deferred premium if any.

Each call spread transaction has an established short call price and long call price. Depending on the terms, the counterparty may pay a premium to the Company to enter into the transaction. When the settlement price is above the short call price up to the long call price, the Company pays its counterparty an amount equal to the difference between the settlement price and the short call price multiplied by the hedged contract volume. When the settlement price is above the long call price, the Company pays the counterparty an amount equal to the difference between the long call price and the short call price multiplied by the hedged contract volume. When the settlement price is at or below the short call price in an individual month in the contract period, the call option expires with no settlement paid by either the Company or the counterparty for that particular month, except with regard to the deferred premium if any.

The Company's oil derivatives are settled based on the month's average daily NYMEX index price for the first nearby month of the West Texas Intermediate Light Sweet Crude Oil Futures Contract. The Company's NGL derivatives are settled based on the month's average daily OPIS index price for Mont Belvieu Purity Ethane and TET Propane. The Company's natural gas derivatives are settled based on the Inside FERC index price for West Texas WAHA for the calculation period.



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Condensed notes to the consolidated financial statements

(Unaudited)

During the three and six months ended June 30, 2017, the Company completed a hedge restructuring by early terminating a swap that resulted in a termination amount to the Company of $4.2 million that was settled in full by applying the proceeds to pay the premium on one new collar entered into during the restructuring. The following details the derivative that was terminated:



	Aggregate volumes (Bbl)	Floor price ($/Bbl)		Ceiling price ($/Bbl)		Contract period
Oil:
Swap	1,095,000	$	52.12	$	52.12	January 2018 - December 2018

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

During the six months ended June 30, 2017, the following derivatives were entered into:



	Aggregate volumes⁽¹⁾	Floor price⁽²⁾		Ceiling price⁽²⁾		Short call price⁽²⁾		Long call price⁽²⁾		Contract period
Oil⁽³⁾:
Call spread⁽⁴⁾	1,140,800	$	—	$	—	$	60.00	$	100.00	July 2017 - December 2017
Call spread⁽⁵⁾	184,000	$	—	$	—	$	60.00	$	80.00	July 2017 - December 2017
Put⁽⁶⁾	1,567,500	$	50.00	$	—	$	—	$	—	January 2018 - December 2018
Collar	584,000	$	50.00	$	60.00	$	—	$	—	January 2018 - December 2018
Collar⁽⁷⁾	3,504,000	$	40.00	$	60.00	$	—	$	—	January 2018 - December 2018
Natural gas:
Collar⁽⁸⁾	10,950,000	$	2.50	$	3.25	$	—	$	—	January 2018 - December 2018

_____________________________________________________________________________


(1)	Oil is in Bbl and natural gas is in MMBtu.


(2)	Oil is in $/Bbl and natural gas is in $/MMBtu.


(3)	There are $6.3 million in deferred premiums associated with these contracts.


(4)	A premium of $0.5 million was settled in full at inception by applying the proceeds to pay the premiums on a put entered into simultaneously.


(5)	A premium of $0.1 million was settled in full at inception by applying the proceeds to pay the premiums on a put entered into simultaneously.


(6)	Premiums of $4.9 million were paid at inception, of which $0.6 million were settled in full at inception by applying the proceeds from the call spreads entered into simultaneously.


(7)	A premium of $4.2 million was settled in full at inception as part of the Company's 2017 hedge restructuring by applying the proceeds of the terminated swap.


(8)	There are $0.9 million in deferred premiums associated with these contracts.



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Condensed notes to the consolidated financial statements

(Unaudited)

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)	2017		2016		2017		2016
Cash settlements received for matured derivatives, net⁽¹⁾	$	13,705	$	47,382	$	21,156	$	113,319
Cash settlements received for early terminations of derivatives, net⁽²⁾	4,234		—		4,234		80,000
Cash settlements received for derivatives, net	$	17,939	$	47,382	$	25,390	$	193,319

_____________________________________________________________________________


(1)	The settlement amounts do not include premiums paid attributable to contracts that matured during the respective period.


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



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Condensed notes to the consolidated financial statements

(Unaudited)

The following table summarizes open positions as of June 30, 2017, and represents, as of such date, derivatives in place through December 2018 on annual production:



	Remaining year 2017		Year 2018
Oil positions:
Puts:
Hedged volume (Bbl)	529,000		2,616,875
Weighted-average price ($/Bbl)	$	60.00	$	54.01
Swaps:
Hedged volume (Bbl)	1,012,000		—
Weighted-average price ($/Bbl)	$	51.54	$	—
Collars:
Hedged volume (Bbl)	1,913,600		4,088,000
Weighted-average floor price ($/Bbl)	$	56.92	$	41.43
Weighted-average ceiling price ($/Bbl)	$	86.00	$	60.00
Call Spreads:
Hedged volume (Bbl)	1,324,800		—
Weighted-average short call price ($/Bbl)	$	60.00	$	—
Weighted-average long call price ($/Bbl)	$	97.22	$	—
Totals:
Total volume hedged with floor price (Bbl)	3,454,600		6,704,875
Weighted-average floor price ($/Bbl)	$	55.82	$	46.34
Total volume hedged with ceiling price (Bbl)	2,925,600		4,088,000
Weighted-average ceiling price ($/Bbl)	$	57.22	$	60.00
NGL positions:
Swaps - Ethane:
Hedged volume (Bbl)	222,000		—
Weighted-average price ($/Bbl)	$	11.24	$	—
Swaps - Propane:
Hedged volume (Bbl)	187,500		—
Weighted-average price ($/Bbl)	$	22.26	$	—
Natural gas positions:
Puts:
Hedged volume (MMBtu)	4,020,000		8,220,000
Weighted-average price ($/MMBtu)	$	2.50	$	2.50
Collars:
Hedged volume (MMBtu)	9,586,400		15,585,500
Weighted-average floor price ($/MMBtu)	$	2.86	$	2.50
Weighted-average ceiling price ($/MMBtu)	$	3.54	$	3.35
Totals:
Total volume hedged with floor price (MMBtu)	13,606,400		23,805,500
Weighted-average floor price ($/MMBtu)	$	2.75	$	2.50
Total volume hedged with ceiling price (MMBtu)	9,586,400		15,585,500
Weighted-average ceiling price ($/MMBtu)	$	3.54	$	3.35



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

b. Balance sheet presentation

In accordance with the Company's standard practice, its derivatives are subject to counterparty netting under their governing agreements. The Company's oil, NGL and natural gas derivatives are presented on a net basis as "Derivatives" on the unaudited consolidated balance sheets. See Note 8.a for a summary of the fair value of derivatives on a gross basis.

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

Note 8—Fair value measurements

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

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

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



Level 1—	Assets and liabilities recorded at fair value for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access. Active markets are considered to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2—	Assets and liabilities recorded at fair value for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the assets or liabilities. Substantially all of these inputs are observable in the marketplace throughout the full term of the price risk management instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace.

Level 3—	Assets and liabilities recorded at fair value for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. Unobservable inputs are not corroborated by market data. These inputs reflect management's own assumptions about the assumptions a market participant would use in pricing the asset or liability.

When the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety. The Company conducts a review of fair value hierarchy classifications on an annual basis. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities. Transfers between fair value hierarchy levels are recognized and reported in the period in which the transfer occurred. No transfers between fair value hierarchy levels occurred during the six months ended June 30, 2017 or 2016.



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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, 2017:
Assets
Current:
Oil derivatives	$	—	$	46,492		$	—		$	46,492		$	(323	)	$	46,169
NGL derivatives	—		110			—			110			(678		)	(568		)
Natural gas derivatives	—		4,452			—			4,452			(1,577		)	2,875
Oil deferred premiums	—		—			—			—			(4,637		)	(4,637		)
Natural gas deferred premiums	—		—			—			—			(854		)	(854		)
Noncurrent:
Oil derivatives	$	—	$	14,712		$	—		$	14,712		$	—		$	14,712
NGL derivatives	—		—			—			—			—			—
Natural gas derivatives	—		2,822			—			2,822			—			2,822
Oil deferred premiums	—		—			—			—			(3,068		)	(3,068		)
Natural gas deferred premiums	—		—			—			—			(1,659		)	(1,659		)
Liabilities
Current:
Oil derivatives	$	—	$	(204	)	$	—		$	(204	)	$	323		$	119
NGL derivatives	—		(678		)	—			(678		)	678			—
Natural gas derivatives	—		(13		)	—			(13		)	1,577			1,564
Oil deferred premiums	—		—			(4,637		)	(4,637		)	4,637			—
Natural gas deferred premiums	—		—			(3,190		)	(3,190		)	854			(2,336		)
Noncurrent:
Oil derivatives	$	—	$	—		$	—		$	—		$	—		$	—
NGL derivatives	—		—			—			—			—			—
Natural gas derivatives	—		—			—			—			—			—
Oil deferred premiums	—		—			(3,068		)	(3,068		)	3,068			—
Natural gas deferred premiums	—		—			(1,659		)	(1,659		)	1,659			—
Net derivative position	$	—	$	67,693		$	(12,554	)	$	55,139		$	—		$	55,139



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Condensed notes to the consolidated financial statements

(Unaudited)



(in thousands)	Level 1		Level 2			Level 3			Total gross fair value			Amounts offset			Net fair value presented on the unaudited consolidated balance sheets
As of December 31, 2016:
Assets
Current:
Oil derivatives	$	—	$	22,527		$	—		$	22,527		$	—		$	22,527
NGL derivatives	—		—			—			—			—			—
Natural gas derivatives	—		270			—			270			(270		)	—
Oil deferred premiums	—		—			—			—			(1,580		)	(1,580		)
Natural gas deferred premiums	—		—			—			—			—			—
Noncurrent:
Oil derivatives	$	—	$	8,718		$	—		$	8,718		$	—		$	8,718
NGL derivatives	—		—			—			—			—			—
Natural gas derivatives	—		1,377			—			1,377			(1,377		)	—
Oil deferred premiums	—		—			—			—			—			—
Natural gas deferred premiums	—		—			—			—			—			—
Liabilities
Current:
Oil derivatives	$	—	$	(9,789	)	$	—		$	(9,789	)	$	—		$	(9,789	)
NGL derivatives	—		(2,803		)	—			(2,803		)	—			(2,803		)
Natural gas derivatives	—		(3,639		)	—			(3,639		)	270			(3,369		)
Oil deferred premiums	—		—			(3,569		)	(3,569		)	1,580			(1,989		)
Natural gas deferred premiums	—		—			(3,043		)	(3,043		)	—			(3,043		)
Noncurrent:
Oil derivatives	$	—	$	(4,552	)	$	—		$	(4,552	)	$	—		$	(4,552	)
NGL derivatives	—		—			—			—			—			—
Natural gas derivatives	—		(133		)	—			(133		)	1,377			1,244
Oil deferred premiums	—		—			—			—			—			—
Natural gas deferred premiums	—		—			(2,386		)	(2,386		)	—			(2,386		)
Net derivative position	$	—	$	11,976		$	(8,998	)	$	2,978		$	—		$	2,978

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

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



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The following table presents actual cash payments required for deferred premiums as of June 30, 2017 for the periods presented:



(in thousands)	June 30, 2017
Remaining 2017	$	2,888
2018	9,375
2019	535
Total	$	12,798

A summary of the changes in net 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)	2017			2016			2017			2016
Balance of Level 3 at beginning of period	$	(13,025	)	$	(13,054	)	$	(8,998	)	$	(14,619	)
Change in net present value of derivative deferred premiums	(70		)	(61		)	(111		)	(133		)
Total purchases and settlements:
Purchases	(905		)	(1,960		)	(6,998		)	(6,072		)
Settlements⁽¹⁾	1,446			2,413			3,553			8,162
Balance of Level 3 at end of period	$	(12,554	)	$	(12,662	)	$	(12,554	)	$	(12,662	)

_____________________________________________________________________________


(1)	The amount for the six months ended June 30, 2016 includes $3.9 million that 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, if any, at fair value on a nonrecurring basis. For purposes of fair value measurement, it was determined that the impairment of long-lived assets is classified as Level 3, based on the use of internally developed cash flow models. No impairments of long-lived assets were recorded during the six months ended June 30, 2017 or 2016.

The Company accounts for the impairment of inventory, if any, at lower of cost or NRV on a nonrecurring basis. For purposes of fair value measurement, it was determined that the impairment of inventory is classified as Level 2, based on the use of a replacement cost approach. See Note 2.i for discussion of the Company's inventory impairments recorded during the three and six months ended June 30, 2016. No impairments of inventory were recorded during the six months ended June 30, 2017.

The accounting policies for impairment of oil and natural gas properties are discussed in Note 2.g. Significant inputs included in the calculation of discounted cash flows used in the impairment analysis include the Company's estimate of operating and development costs, anticipated production of evaluated reserves and other relevant data. See Note 2.g for discussion of the Company's full cost ceiling impairment recorded during the six months ended June 30, 2016. There were no full cost ceiling impairments recorded during the six months ended June 30, 2017.

The Company accounts for acquisitions of evaluated and unevaluated oil and natural gas properties under the acquisition method of accounting. Accordingly, the Company conducts assessments of net assets acquired and recognizes amounts for identifiable assets acquired and liabilities assumed at the estimated acquisition date fair values, while transaction costs associated with the acquisitions are expensed as incurred.

The Company makes various assumptions in estimating the fair values of assets acquired and liabilities assumed. The most significant assumptions relate to the estimated fair value of evaluated and unevaluated oil and natural gas properties. The fair value of these properties are measured using a discounted cash flow model that converts future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) forecasted oil, NGL and natural gas reserve quantities; (ii) future commodity strip prices as of the closing dates adjusted for transportation and regional price differentials; (iii) forecasted ad valorem taxes, production taxes, income taxes, general and administrative expenses, operating expenses and development costs; and (iv) a peer group weighted-average cost of capital rate subject to additional project-specific risk factors. To compensate for the inherent risk of estimating the value of the unevaluated properties, the discounted future net revenues of proved undeveloped and probable reserves are reduced by additional reserve adjustment factors. These assumptions represent



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Level 3 inputs under the fair value hierarchy. No acquisitions of evaluated and unevaluated oil and natural gas properties were recorded during the six months ended June 30, 2017 or 2016.

Note 9—Net income (loss) per common share

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

The effect of the Company's outstanding stock option awards, with the exception of the options granted in 2016, was excluded from the calculation of diluted net income per common share for the three and six months ended June 30, 2017. The inclusion of these options would be anti-dilutive due to the following: (i) utilizing the treasury stock method, the sum of the assumed proceeds exceeded the average stock prices during the respective periods for the outstanding stock option awards granted in 2015 and (ii) the exercise prices were greater than the average market prices during the respective periods for the outstanding stock option awards granted in 2012, 2013, 2014 and 2017.

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



	Three months ended June 30,					Six months ended June 30,
(in thousands, except for per share data)	2017		2016			2017		2016
Net income (loss) (numerator):
Net income (loss)—basic and diluted	$	61,110	$	(71,432	)	$	129,386	$	(251,803	)
Weighted-average common shares outstanding (denominator):
Basic	239,231		217,564			238,870		214,562
Non-vested performance share awards⁽¹⁾	4,666		—			4,488		—
Non-vested restricted stock awards⁽²⁾	419		—			896		—
Outstanding stock option awards⁽²⁾	101		—			131		—
Diluted	244,417		217,564			244,385		214,562
Net income (loss) per common share:
Basic	$	0.26	$	(0.33	)	$	0.54	$	(1.17	)
Diluted	$	0.25	$	(0.33	)	$	0.53	$	(1.17	)

_____________________________________________________________________________

(1)

For the three and six months ended June 30, 2017, the dilutive effect of non-vested performance share awards with performance periods that have not yet ended was calculated utilizing the Company's total shareholder return ("TSR") from the beginning of each performance share awards' respective performance period to June 30, 2017 in comparison to the TSR of the peers specified in each performance share awards' respective agreement. See Note 5.c for additional discussion of the Company's performance share awards.


(2)	For the three and six months ended June 30, 2017, the dilutive effects of the non-vested restricted stock awards and the outstanding stock option awards were calculated utilizing the treasury stock method. See Notes 5.a and 5.b for additional discussion of the Company's restricted stock awards and stock option awards, respectively.

Note 10—Credit risk

The Company's oil, NGL and natural gas sales are made to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. The Company's joint operations accounts receivable are from a number of oil and natural gas companies, partnerships, individuals and others who own interests in the oil and natural gas properties operated by the Company. The Company's sales of purchased oil are 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.



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The Company uses derivatives to hedge its exposure to oil, NGL and natural gas price volatility. These transactions expose the Company to potential credit risk from its counterparties. In accordance with the Company's standard practice, its derivatives are subject to counterparty netting under agreements governing such derivatives; therefore, the credit risk associated with its derivative counterparties is somewhat mitigated. See Notes 2.e, 7 and 8.a for additional information regarding the Company's derivatives.

Note 11—Commitments and contingencies

a. Litigation

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

On May 3, 2017, Shell Trading (US) Company ("Shell") filed an Original Petition and Request for Disclosure in the District Court of Harris County, Texas, alleging that the crude oil purchase agreement entered into between Shell and Laredo effective October 1, 2016 does not reflect the compensation for Shell that Shell believes was previously agreed to by the parties due to a drafting mistake. Shell seeks reformation of one clause of the crude oil purchase agreement on the grounds of alleged mutual mistake or, in the alternative, unilateral mistake; an award of the amounts Shell alleges it should have been or should be paid under the agreement; court costs and attorneys’ fees. The Company does not believe there was a drafting mistake made in the crude oil purchase agreement. The Company believes it has substantive defenses and intends to vigorously defend its position. The Company is unable to determine the outcome or estimate its ultimate exposure, if any, to this litigation at this time.

b. Drilling contracts

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 a penalty to the third party should the Company cease drilling efforts. This penalty would negatively impact the Company's financial statements upon early contract termination. There were no penalties incurred for early contract termination for either of the six months ended June 30, 2017 or 2016. The future commitment of $2.3 million as of June 30, 2017 is not recorded in the accompanying unaudited consolidated balance sheets. Management does not currently anticipate the early termination of this contract in 2017.

c. Firm sale and transportation commitments

The Company has committed to deliver for sale or transportation fixed volumes of product under certain contractual arrangements that specify the delivery of a fixed and determinable quantity. If not fulfilled, the Company is subject to deficiency payments. These commitments are normal and customary for the Company's business. In certain instances, the Company has used spot market purchases to meet its commitments in certain locations or due to favorable pricing. Management anticipates continuing this practice in the future. The Company incurred deficiency payments of $0.5 million and $0.6 million during the three and six months ended June 30, 2017, respectively, which are reported on the unaudited consolidated statements of operations in the "Other operating expenses" line item. There were no deficiency payments during the six months ended June 30, 2016. Future commitments of $381.8 million as of June 30, 2017 are not recorded in the accompanying unaudited consolidated balance sheets.

d. Federal and state regulations

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



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Note 12—Related parties

a. Medallion

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



(in thousands)	June 30, 2017		December 31, 2016
Accounts receivable, net	$	59	$	—
Accrued capital expenditures	$	379	$	586
Other current liabilities	$	102	$	118

b. Archrock Partners, L.P.

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

As of December 31, 2016, amounts included in accounts payable from Archrock in the unaudited consolidated balance sheets totaled $0.2 million. No such amounts were included as of June 30, 2017.

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



	Three months ended June 30,				Six months ended June 30,
(in thousands)	2017		2016		2017		2016
Lease operating expenses	$	232	$	526	$	656	$	1,001

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)	2017		2016		2017		2016
Capital expenditures:
Midstream service assets	$	108	$	—	$	108	$	20

Note 13—Segments



Table of Contents	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, 2017:
Revenues:
Oil, NGL and natural gas sales	$	142,288	$	825		$	(1,276	)	$	141,837
Midstream service revenues	—		18,104			(15,401		)	2,703
Sales of purchased oil	—		42,461			—			42,461
Total revenues	142,288		61,390			(16,677		)	187,001
Costs and expenses:
Lease operating expenses, including production and ad valorem taxes	31,993		—			(3,417		)	28,576
Midstream service expenses	—		11,978			(11,082		)	896
Costs of purchased oil	—		44,020			—			44,020
General and administrative⁽¹⁾	20,121		1,887			—			22,008
Depletion, depreciation and amortization⁽²⁾	35,683		2,320			—			38,003
Other operating expenses⁽³⁾	1,382		55			—			1,437
Operating income	$	53,109	$	1,130		$	(2,178	)	$	52,061
Other financial information:
Income from equity method investee	$	—	$	2,471		$	—		$	2,471
Interest expense⁽⁴⁾	$	21,752	$	1,421		$	—		$	23,173
Capital expenditures	$	123,157	$	4,386		$	—		$	127,543
Gross property and equipment⁽⁵⁾	$	5,979,858	$	412,177		$	(13,226	)	$	6,378,809
Three months ended June 30, 2016:
Revenues:
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
Costs and expenses:
Lease operating expenses, including production and ad valorem taxes	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 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⁽⁵⁾	$	5,484,416	$	366,858		$	(4,604	)	$	5,846,670
Six months ended June 30, 2017:
Revenues:
Oil, NGL and natural gas sales	$	281,496	$	1,641		$	(2,564	)	$	280,573
Midstream service revenues	—		35,738			(30,036		)	5,702
Sales of purchased oil	—		89,732			—			89,732
Total revenues	281,496		127,111			(32,600		)	376,007
Costs and expenses:
Lease operating expenses, including production and ad valorem taxes	61,563		—			(7,214		)	54,349
Midstream service expenses	—		22,212			(20,400		)	1,812
Costs of purchased oil	—		94,276			—			94,276
General and administrative⁽¹⁾	43,564		4,041			—			47,605
Depletion, depreciation and amortization⁽²⁾	67,480		4,635			—			72,115
Other operating expenses⁽³⁾	2,355		108			—			2,463
Operating income	$	106,534	$	1,839		$	(4,986	)	$	103,387
Other financial information:
Income from equity method investee	$	—	$	5,539		$	—		$	5,539
TABLE CONTINUES ON NEXT PAGE



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)



(in thousands)	Exploration and production			Midstream and marketing			Eliminations			Consolidated company
Interest expense⁽⁴⁾	$	43,066		$	2,827		$	—		$	45,893
Capital expenditures	$	234,902		$	6,117		$	—		$	241,019
Gross property and equipment⁽⁵⁾	$	5,979,858		$	412,177		$	(13,226	)	$	6,378,809
Six months ended June 30, 2016:
Revenues:
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
Costs and expenses:
Lease operating expenses, including production and ad valorem taxes	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 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⁽⁵⁾	$	5,484,416		$	366,858		$	(4,604	)	$	5,846,670

_______________________________________________________________________________

(1)

General and administrative expenses were allocated to the three months ended June 30, 2017, March 31, 2017, June 30, 2016 and March 31, 2016 based on the number of employees in the respective segment as of the respective three-month period end dates. Certain components of general and administrative expenses, primarily payroll, deferred compensation and vehicle expenses, were not allocated but were actual expenses for each segment. Land and geology expenses were not allocated to the midstream and marketing segment.

(2)

Depletion, depreciation and amortization were actual expenses for each segment with the exception of the allocation of depreciation of other fixed assets, which were allocated to the three months ended June 30, 2017, March 31, 2017, June 30, 2016 and March 31, 2016 based on the number of employees in the respective segment as of the respective three-month period end dates. Certain components of depreciation and amortization of other fixed assets, primarily vehicles, were not allocated but were actual expenses for each segment.


(3)	Other operating expenses consist of (i) accretion of asset retirement obligations and minimum volume commitments for the three and six months ended June 30, 2017 and (ii) accretion of asset retirement obligations for the three and six months ended June 30, 2016. These were actual expenses and were not allocated.

(4)

Interest expense for the three months ended June 30, 2017 and March 31, 2017 was allocated to the exploration and production segment based on gross property and equipment as of June 30, 2017 and March 31, 2017, respectively, and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of June 30, 2017 and March 31, 2017, respectively. Interest expense for the three and six months ended June 30, 2016 was allocated to the exploration and production segment based on gross property and equipment as of June 30, 2016 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of June 30, 2016. Certain components of other fixed assets, primarily vehicles, were not allocated but were actual assets for the each segment.

(5)

Gross property and equipment for the midstream and marketing segment includes equity method investment of $249.5 million and $213.6 million as of June 30, 2017 and 2016, respectively. Other fixed assets were allocated based on the number of employees in the respective segment as of June 30, 2017 and 2016. Certain components of other fixed assets, primarily vehicles, were not allocated but were actual assets for each segment.



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Note 14—Subsidiary guarantors

The Guarantors have fully and unconditionally guaranteed the January 2022 Notes, the May 2022 Notes, the March 2023 Notes and the Senior Secured Credit Facility, subject to the Releases. In accordance with practices accepted by the SEC, Laredo has prepared condensed consolidating financial statements to quantify the balance sheets, results of operations and cash flows of such subsidiaries as subsidiary guarantors. The following unaudited condensed consolidating balance sheets as of June 30, 2017 and December 31, 2016, unaudited condensed consolidating statements of operations for the three and six months ended June 30, 2017 and 2016 and unaudited condensed consolidating statements of cash flows for the six months ended June 30, 2017 and 2016 present financial information for Laredo on a stand-alone basis (carrying any investment in subsidiaries under the equity method), financial information for the subsidiary guarantors on a stand-alone basis (carrying any investment in subsidiaries under the equity method), and the consolidation and elimination entries necessary to arrive at the information for the Company on a condensed consolidated basis. Deferred income taxes for LMS and for GCM are recorded on Laredo's balance sheets, statements of operations and statements of cash flows as they are disregarded entities for income tax purposes. Laredo and the Guarantors are not restricted from making intercompany distributions to each other. During the six months ended June 30, 2016, certain assets were transferred from LMS to Laredo at historical cost.

Condensed consolidating balance sheet

June 30, 2017

(Unaudited)



(in thousands)	Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Accounts receivable, net	$	60,506	$	11,601	$	—		$	72,107
Other current assets	92,062		3,495		—			95,557
Oil and natural gas properties, net	1,332,884		9,272		(13,226		)	1,328,930
Midstream service assets, net	—		128,941		—			128,941
Other fixed assets, net	40,966		449		—			41,415
Investment in subsidiaries and equity method investment	384,303		249,492		(384,303		)	249,492
Other long-term assets	21,104		3,708		—			24,812
Total assets	$	1,931,825	$	406,958	$	(397,529	)	$	1,941,254

Accounts payable	$	8,984	$	1,793	$	—		$	10,777
Other current liabilities	143,673		17,633		—			161,306
Long-term debt, net	1,390,277		—		—			1,390,277
Other long-term liabilities	51,262		3,229		—			54,491
Stockholders' equity	337,629		384,303		(397,529		)	324,403
Total liabilities and stockholders' equity	$	1,931,825	$	406,958	$	(397,529	)	$	1,941,254



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Condensed consolidating balance sheet

December 31, 2016

(Unaudited)



(in thousands)	Laredo		Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Accounts receivable, net	$	70,570	$	16,297	$	—		$	86,867
Other current assets	65,884		2,026		—			67,910
Oil and natural gas properties, net	1,194,801		9,293		(8,240		)	1,195,854
Midstream service assets, net	—		126,240		—			126,240
Other fixed assets, net	44,221		552		—			44,773
Investment in subsidiaries and equity method investment	376,028		243,953		(376,028		)	243,953
Other long-term assets	13,065		3,684		—			16,749
Total assets	$	1,764,569	$	402,045	$	(384,268	)	$	1,782,346

Accounts payable	$	14,427	$	627	$	—		$	15,054
Other current liabilities	150,531		22,360		—			172,891
Long-term debt, net	1,353,909		—		—			1,353,909
Other long-term liabilities	56,889		3,030		—			59,919
Stockholders' equity	188,813		376,028		(384,268		)	180,573
Total liabilities and stockholders' equity	$	1,764,569	$	402,045	$	(384,268	)	$	1,782,346

Condensed consolidating statement of operations

For the three months ended June 30, 2017

(Unaudited)



(in thousands)	Laredo			Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Total revenues	$	142,224		$	61,454	$	(16,677	)	$	187,001
Total costs and expenses	91,140			58,299		(14,499		)	134,940
Operating income	51,084			3,155		(2,178		)	52,061
Interest expense	(23,173		)	—		—			(23,173		)
Other non-operating income	35,377			2,414		(5,569		)	32,222
Income before income tax	63,288			5,569		(7,747		)	61,110
Income tax	—			—		—			—
Net income	$	63,288		$	5,569	$	(7,747	)	$	61,110

Condensed consolidating statement of operations

For the six months ended June 30, 2017

(Unaudited)



(in thousands)	Laredo			Subsidiary Guarantors		Intercompany eliminations			Consolidated company
Total revenues	$	281,367		$	127,240	$	(32,600	)	$	376,007
Total costs and expenses	179,169			121,065		(27,614		)	272,620
Operating income	102,198			6,175		(4,986		)	103,387
Interest expense	(45,893		)	—		—			(45,893		)
Other non-operating income	78,067			5,332		(11,507		)	71,892
Income before income tax	134,372			11,507		(16,493		)	129,386
Income tax	—			—		—			—
Net income	$	134,372		$	11,507	$	(16,493	)	$	129,386

Condensed consolidating statement of operations



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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	(23,512		)	—		—			(23,512		)
Other non-operating income (expense)	(64,768		)	3,692		(4,718		)	(65,794		)
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	(47,217		)	—		—			(47,217		)
Other non-operating income (expense)	(43,337		)	5,983		(8,318		)	(45,672		)
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 cash flows

For the six months ended June 30, 2017

(Unaudited)



(in thousands)	Laredo			Subsidiary Guarantors			Intercompany eliminations			Consolidated company
Net cash provided by operating activities	$	159,048		$	9,360		$	(11,507	)	$	156,901
Change in investment between affiliates	(8,264		)	(3,243		)	11,507			—
Capital expenditures and other	(171,461		)	(6,117		)	—			(177,578		)
Net cash provided by financing activities	23,029			—			—			23,029
Net increase in cash and cash equivalents	2,352			—			—			2,352
Cash and cash equivalents, beginning of period	32,671			1			—			32,672
Cash and cash equivalents, end of period	$	35,023		$	1		$	—		$	35,024



Table of Contents	Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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 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 provided by financing activities	93,154			—			—			93,154
Net decrease in cash and cash equivalents	(11,845		)	—			—			(11,845		)
Cash and cash equivalents, beginning of period	31,153			1			—			31,154
Cash and cash equivalents, end of period	$	19,308		$	1		$	—		$	19,309

Note 15—Recently issued or adopted accounting pronouncements

The Company considers the applicability and impact of all accounting standard updates ("ASU") issued by the Financial Accounting Standards Board ("FASB"). The ASUs listed below were either adopted during the six months ended June 30, 2017 or the discussion of the ASU was determined to be meaningful to the Company's 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. In March, April, May and December 2016, the FASB issued new guidance in Topic 606, Revenue from Contracts with Customers, to address the following potential implementation issues of the new revenue standard: (a) to clarify the implementation guidance on principal versus agent considerations, (b) to clarify the identification of performance obligations and the licensing implementation guidance and (c) to address certain issues in the guidance on assessing collectability, presentation of sales taxes, noncash consideration, and completed contracts and contract modifications at transition. This standard is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company follows the sales method of accounting for oil, NGL and natural gas production, which is generally consistent with the revenue recognition provision of the new standard. However, the Company is still evaluating the impact this standard will have on its consolidated financial statements upon adoption. The evaluation process includes (i) review of revenue contracts and transactions in both of the exploration and production and midstream and marketing segments and (ii) assessing the impact this guidance will have on our processes and internal controls. The Company expects to apply the modified retrospective method upon adoption of this standard on the effective date of January 1, 2018.

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 lease guidance. In addition, also consistent with the previous lease guidance, a lessee (and a lessor) should exclude most variable lease payments in measuring lease assets and lease



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Condensed notes to the consolidated financial statements

(Unaudited)

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

In January 2017, the FASB issued new guidance in Topic 805, Business Combinations, to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. Under the current implementation guidance in Topic 805, there are three elements of a business—inputs, processes and outputs. While an integrated set of assets and activities (collectively referred to as a “set”) that is a business usually has outputs, outputs are not required to be present. In addition, all the inputs and processes that a seller uses in operating a set are not required if market participants can acquire the set and continue to produce outputs, for example, by integrating the acquired set with their own inputs and processes. The amendments in this ASU provide a screen to determine when a set is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. This screen reduces the number of transactions that need to be further evaluated. If the screen is not met, the amendments in this ASU (i) require that to be considered a business, a set must include, at a minimum, an input and a substantive process that together significantly contribute to the ability to create an output and (ii) remove the evaluation of whether a market participant could replace missing elements. The amendments provide a framework to assist entities in evaluating whether both an input and a substantive process are present. The framework includes two sets of criteria to consider that depend on whether a set has outputs. Although outputs are not required for a set to be a business, outputs generally are a key element of a business; therefore, the FASB has developed more stringent criteria for sets without outputs. Lastly, the amendments in this ASU narrow the definition of the term output so that the term is consistent with how outputs are described in Topic 606. The amendments in this ASU are effective for annual periods beginning after December 15, 2017, including interim periods within those periods. The amendments in this ASU should be applied prospectively on or after the effective date. Early application of the amendments in this ASU is permitted. The Company is currently evaluating the impact this standard will have on its consolidated financial statements upon adoption.

Note 16—Subsequent events

a. Senior Secured Credit Facility

On July 12, 2017, the Company borrowed $10.0 million on the Senior Secured Credit Facility. The outstanding balance under the Senior Secured Credit Facility was $115.0 million as of August 7, 2017.

b. Medallion capital call

Subsequent to June 30, 2017, the Company approved $24.6 million to fund continued expansion activities on existing portions of Medallion's pipeline infrastructure in order to gather additional third-party production. See Note 2.h for additional discussion regarding Medallion and see Note 12.a for discussion of items included in the Company's unaudited consolidated financial statements related to Medallion.



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Condensed notes to the consolidated financial statements

(Unaudited)

Note 17—Supplementary information

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

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



	Three months ended June 30,				Six months ended June 30,
(in thousands)	2017		2016		2017		2016
Property acquisition costs:							—
Evaluated	$	—	$	—	$	—	$	—
Unevaluated	—		—		—		—
Exploration costs	5,658		19,769		21,201		27,032
Development costs⁽¹⁾	125,738		70,806		236,896		152,692
Total costs incurred	$	131,396	$	90,575	$	258,097	$	179,724

____________________________________________________________________________


(1)	Development costs include $0.1 million in asset retirement obligations for each of the three months ended June 30, 2017 and 2016, and $0.2 million for each of the six months ended June 30, 2017 and 2016.

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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our unaudited consolidated financial statements and condensed notes thereto included elsewhere in this Quarterly Report as well as our audited consolidated financial statements and notes thereto included in our 2016 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 gathering of oil and liquids-rich 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, 2017 included the following:


•	Oil, NGL and natural gas sales of $141.8 million, compared to $102.5 million for the three months ended June 30, 2016;


•	Average daily sales volumes of 58,632 BOE/D, compared to 47,667 BOE/D for the three months ended June 30, 2016;


•	Net income of $61.1 million, compared to a net loss of $71.4 million, for the three months ended June 30, 2016; and


•	Adjusted EBITDA (a non-GAAP financial measure) of $114.3 million, compared to $110.0 million for the three months ended June 30, 2016. See page 49 for a discussion and reconciliation of Adjusted EBITDA.

Our financial and operating performance for the six months ended June 30, 2017 included the following:


•	Oil, NGL and natural gas sales of $280.6 million, compared to $175.7 million for the six months ended June 30, 2016;


•	Average daily sales volumes of 55,536 BOE/D, compared to 46,935 BOE/D for the six months ended June 30, 2016;


•	Net income of $129.4 million, compared to a net loss of $251.8 million, including a non-cash full cost ceiling impairment of $161.1 million, for the six months ended June 30, 2016; and


•	Adjusted EBITDA (a non-GAAP financial measure) of $221.7 million, compared to $208.3 million for the six months ended June 30, 2016. See page 49 for a discussion and reconciliation of Adjusted EBITDA.

Pricing and reserves

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

For the three months ended June 30, 2017 and 2016, the Realized Prices utilized to value our reserves were $43.64 per Bbl for oil, $15.16 per Bbl for NGL and $2.15 per Mcf for natural gas, and $37.96 per Bbl for oil, $10.80 per Bbl for NGL and $1.64 per Mcf for natural gas, respectively. The Realized Prices used to estimate proved reserves for all periods do not include derivative transactions. The unamortized cost of our evaluated oil and natural gas properties did not exceed the full cost ceiling amount as of June 30, 2017, March 31, 2017 or June 30, 2016 and as such, we did not record a 2017 second-quarter, 2017 first-quarter or 2016 second-quarter, respectively, full cost ceiling impairment. See Note 2.g to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for a discussion regarding prices used to value our reserves and our 2016 first-quarter full cost ceiling impairment.

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

Core areas of operations

The oil and liquids-rich Permian Basin is characterized by multiple target horizons, extensive production histories, long-lived reserves, high drilling success rates and high initial production rates. As of June 30, 2017, we had assembled 125,967 net acres in the Permian Basin.

Sources of our revenue

Our revenues are derived from the sale of produced oil, NGL and natural gas within the continental United States, the sale of purchased oil and providing midstream services to third parties. Our revenues do not include the effects of derivatives. For the three months ended June 30, 2017, our revenues were comprised of 56% sales of produced oil, 11% sales of produced NGL, 9% sales of produced natural gas, 23% sales of purchased oil and 1% midstream services. For the six months ended June 30, 2017, our revenues were comprised of 54% sales of produced oil, 11% sales of produced NGL, 10% sales of produced natural gas, 24% sales of purchased oil and 1% 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.

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Results of operations consolidated

For the three and six months ended June 30, 2017 as compared to the three and six months ended June 30, 2016

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,
	2017			2016			2017			2016
Sales volumes:
Oil (MBbl)	2,482			2,012			4,602			4,018
NGL (MBbl)	1,433			1,153			2,696			2,219
Natural gas (MMcf)	8,524			7,038			16,524			13,834
Oil equivalents (MBOE)⁽¹⁾⁽²⁾	5,336			4,338			10,052			8,542
Average daily sales volumes (BOE/D)⁽²⁾	58,632			47,667			55,536			46,935
% Oil	47		%	46		%	46		%	47		%
Oil, NGL and natural gas sales (in thousands):
Oil	$	104,214		$	79,201		$	203,681		$	134,395
NGL	19,801			14,120			40,629			23,172
Natural gas	17,822			9,205			36,263			18,101
Total oil, NGL and natural gas sales	$	141,837		$	102,526		$	280,573		$	175,668
Average sales prices⁽²⁾:
Oil, realized ($/Bbl)⁽³⁾	$	42.00		$	39.37		$	44.26		$	33.45
NGL, realized ($/Bbl)⁽³⁾	$	13.82		$	12.24		$	15.07		$	10.44
Natural gas, realized ($/Mcf)⁽³⁾	$	2.09		$	1.31		$	2.19		$	1.31
Average price, realized ($/BOE)⁽³⁾	$	26.58		$	23.64		$	27.91		$	20.56
Oil, hedged ($/Bbl)⁽⁴⁾	$	46.95		$	58.86		$	48.22		$	57.85
NGL, hedged ($/Bbl)⁽⁴⁾	$	13.61		$	12.24		$	14.75		$	10.44
Natural gas, hedged ($/Mcf)⁽⁴⁾	$	2.12		$	2.13		$	2.21		$	2.10
Average price, hedged ($/BOE)⁽⁴⁾	$	28.88		$	34.00		$	29.66		$	33.33

________________________________________________________________________


(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.

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The following table presents cash settlements received (paid) 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)	2017			2016			2017			2016
Cash settlements received (paid) for matured derivatives:
Oil	$	12,969		$	41,616		$	20,217		$	102,308
NGL	(296		)	—			(864		)	—
Natural gas	1,032			5,766			1,803			11,011
Total	$	13,705		$	47,382		$	21,156		$	113,319
Premiums paid attributable to contracts that matured during the respective period:
Oil	$	(679	)	$	(2,413	)	$	(2,021	)	$	(4,263	)
Natural gas	(767		)	—			(1,532		)	—
Total	$	(1,446	)	$	(2,413	)	$	(3,553	)	$	(4,263	)

Changes in average realized sales prices and sales volumes caused the following changes to our oil, NGL and natural gas revenues between the three months ended June 30, 2017 and 2016:



(in thousands)	Oil		NGL		Natural gas		Total net effect of change
2016 Revenues	$	79,201	$	14,120	$	9,205	$	102,526
Effect of changes in average realized sales prices	6,508		2,253		6,672		15,433
Effect of changes in sales volumes	18,505		3,428		1,945		23,878
2017 Revenues	$	104,214	$	19,801	$	17,822	$	141,837

Changes in average realized sales prices and sales volumes caused the following changes to our oil, NGL and natural gas revenues between the six months ended June 30, 2017 and 2016:



(in thousands)	Oil		NGL		Natural gas		Total net effect of change
2016 Revenues	$	134,395	$	23,172	$	18,101	$	175,668
Effect of changes in average realized sales prices	49,747		12,472		14,642		76,861
Effect of changes in sales volumes	19,539		4,985		3,520		28,044
2017 Revenues	$	203,681	$	40,629	$	36,263	$	280,573

Oil revenue. Our oil revenue is a function of oil production volumes sold and average sales prices received for those volumes. The increase in oil revenue of $25.0 million, or 32%, for the three months ended June 30, 2017 as compared to the three months ended June 30, 2016 is due to a 23% increase in oil sales volumes and a 7% increase in average oil prices realized.

The increase in oil revenue of $69.3 million, or 52%, for the six months ended June 30, 2017 as compared to the six months ended June 30, 2016 is due to a 32% increase in average oil prices realized and a 15% increase in oil sales volumes.

NGL revenue. Our NGL revenue is a function of NGL production volumes sold and average sales prices received for those volumes. The increase in NGL revenue of $5.7 million, or 40%, for the three months ended June 30, 2017 as compared to the three months ended June 30, 2016 is due to a 24% increase in NGL sales volumes and a 13% increase in average NGL prices realized.

The increase in NGL revenue of $17.5 million, or 75%, for the six months ended June 30, 2017 as compared to the six months ended June 30, 2016 is due to a 44% increase in average NGL prices realized and a 21% increase in NGL sales volumes.

Natural gas revenue. Our natural gas revenue is a function of natural gas production volumes sold and average sales prices received for those volumes. The increase in natural gas revenue of $8.6 million, or 94%, for the three months ended June 30, 2017 as compared to the three months ended June 30, 2016 is due to a 60% increase in average natural gas prices realized and an 21% increase in natural gas sales volumes.

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The increase in natural gas revenue of $18.2 million, or 100%, for the six months ended June 30, 2017 as compared to the six months ended June 30, 2016 is due to a 67% increase in average natural gas prices realized and an 19% increase in natural gas sales volumes.

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)	2017		2016		2017		2016
Costs and expenses:
Lease operating expenses	$	20,104	$	19,225	$	37,096	$	39,743
Production and ad valorem taxes	8,472		7,982		17,253		14,417
Midstream service expenses	896		1,178		1,812		1,787
Costs of purchased oil	44,020		44,012		94,276		76,958
General and administrative:
Cash	13,321		14,429		29,694		30,042
Non-cash stock-based compensation, net of amounts capitalized	8,687		6,073		17,911		9,911
Depletion, depreciation and amortization	38,003		34,177		72,115		75,655
Impairment expense	—		963		—		162,027
Other operating expenses	1,437		860		2,463		1,704
Total	$	134,940	$	128,899	$	272,620	$	412,244
Average costs per BOE sold⁽¹⁾:
Lease operating expenses	$	3.77	$	4.43	$	3.69	$	4.65
Production and ad valorem taxes	1.59		1.84		1.72		1.69
Midstream service expenses	0.17		0.27		0.18		0.21
General and administrative:
Cash	2.50		3.33		2.95		3.52
Non-cash stock-based compensation, net of amounts capitalized	1.63		1.40		1.78		1.16
Depletion, depreciation and amortization	7.12		7.88		7.17		8.86
Total	$	16.78	$	19.15	$	17.49	$	20.09

________________________________________________________________________


(1)	Average costs per BOE sold are based on actual amounts and are not calculated using the rounded numbers presented in the table above.

Lease operating expenses. Lease operating expenses, which include workover expenses, increased by $0.9 million, or 5%, and decreased by $2.6 million, or 7%, for the three and six months ended June 30, 2017, respectively, compared to the same periods in 2016. On a per BOE sold basis, lease operating expenses decreased 15% and 21% for the three and six months ended June 30, 2017, respectively, compared to the same periods in 2016 mainly due to previous investments in field infrastructure. We continue to focus on economic efficiencies associated with the usage and procurement of products and services related to lease operating expenses.

Production and ad valorem taxes. Production and ad valorem taxes increased by $0.5 million, or 6%, and $2.8 million, or 20%, for the three and six months ended June 30, 2017, respectively, compared to the same periods in 2016. The quarter-over-quarter increase is due to a $1.7 million increase in production taxes partially offset by a $1.2 million decrease in ad valorem taxes. The year-to-date increase over the comparable period in 2016 is due to a $5.2 million increase in production taxes partially offset by a $2.4 million decrease in ad valorem taxes. Production taxes are based on and fluctuate in proportion to our oil, NGL and natural gas revenue. Ad valorem taxes are based on and fluctuate in proportion to the taxable value assessed by the various counties where our oil and natural gas properties are located.

Midstream service expenses. 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"). G&A increased by $1.5 million, or 7%, and $7.7 million, or 19%, for the three and six months ended June 30, 2017, respectively, compared to the same periods in 2016. The most significant change in our G&A was stock-based compensation, net of amounts capitalized, which increased by $2.6 million, or 43%, and $8.0 million, or 81%, for the three and six months ended June 30, 2017, respectively, compared to the same periods in 2016. These increases are mainly due to the timing of our annual issuance of restricted stock awards, stock option awards and performance share awards under our LTIP, which occurred during the first quarter of 2017 and during the second quarter of 2016. The quarter-over-quarter increase in G&A was partially offset by a decrease in salaries, benefits and bonuses, net of amounts capitalized of $0.7 million.

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 restricted stock option awards were determined using a Black-Scholes valuation model in accordance with GAAP and are being expensed on a straight-line basis over their associated four-year requisite service periods.

Our performance share awards are accounted for as equity awards and are included in stock-based compensation expense. The fair values for each of our performance share awards issued were based on a projection of the performance of our stock price relative to a peer group, defined in each performance share 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.n and 5 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information regarding our stock and performance-based compensation.

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



	Three months ended June 30,				Six months ended June 30,
(in thousands except for per BOE sold data)	2017		2016		2017		2016
Depletion of evaluated oil and natural gas properties	$	34,338	$	30,630	$	64,752	$	68,457
Depreciation of midstream service assets	2,177		2,097		4,328		4,168
Depreciation and amortization of other fixed assets	1,488		1,450		3,035		3,030
Total DD&A	$	38,003	$	34,177	$	72,115	$	75,655
DD&A per BOE sold	$	7.12	$	7.88	$	7.17	$	8.86

DD&A increased by $3.8 million, or 11%, and decreased by $3.5 million, or 5%, for the three and six months ended June 30, 2017, respectively, compared to the same periods in 2016. On a per BOE sold basis, DD&A decreased for each of the three and six months ended June 30, 2017 compared to the same periods in 2016, mainly due to positive well results.

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 a result, we recorded a non-cash full cost ceiling impairment of $161.1 million. There were no comparable full cost ceiling impairments recorded during the three and six months ended June 30, 2017 or the three months ended June 30, 2016. For further discussion of our non-cash full cost ceiling impairment accounting policy, see Note 2.g to our unaudited consolidated financial statements included elsewhere in this Quarterly Report. There were no long-lived assets impairments recorded during the six months ended June 30, 2017 and 2016. Inventory impairments of $1.0 million were recorded for each of the three and six months ended June 30, 2016. There were no inventory impairments recorded during the six months ended June 30, 2017. For further discussion of long-lived assets and inventory impairment accounting policies, see Note 2.i to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.

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Non-operating income (expense)

The following table sets forth the components of non-operating income (expense) for the periods presented:



	Three months ended June 30,						Six months ended June 30,
(in thousands)	2017			2016			2017			2016
Non-operating income (expense):
Gain (loss) on derivatives, net	$	28,897		$	(68,518	)	$	65,568		$	(50,633	)
Income from equity method investee	2,471			3,696			5,539			5,994
Interest expense	(23,173		)	(23,512		)	(45,893		)	(47,217		)
Interest and other income	49			11			194			110
Write-off of debt issuance costs	—			(842		)	—			(842		)
Gain (loss) on disposal of assets, net	805			(141		)	591			(301		)
Non-operating income (expense), net	$	9,049		$	(89,306	)	$	25,999		$	(92,889	)

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



(in thousands)	Three months ended June 30, 2017 compared to 2016			Six months ended June 30, 2017 compared to 2016
Changes in gain (loss) on derivatives, net:
Fair value of derivatives outstanding	$	126,858		$	284,130
Cash settlements received for matured derivatives, net	(33,677		)	(92,163		)
Cash settlements received for early terminations of derivatives, net	4,234			(75,766		)
Total changes in gain (loss) on derivatives, net	$	97,415		$	116,201

The changes in fair value of derivatives outstanding are the result of new and expiring contracts and the changing relationship between our outstanding contract prices and the future market prices in the forward curves, which we use to calculate the fair value of our derivatives. In general, if no contracts were entered into, terminated or modified, we experience gains during periods of decreasing market prices and losses during periods of increasing market prices. Net 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.

During the three and six months ended June 30, 2017, we received proceeds from a hedge restructuring in which we early terminated a derivative contract swap, resulting in a termination amount due to us of $4.2 million. The $4.2 million was settled in full by applying the proceeds to pay the premium on one new derivative contract collar entered into during the restructuring.

During the six months ended June 30, 2016, we received proceeds from a hedge restructuring in which we early terminated floors of certain derivative contract collars, resulting in a termination amount due to us of $80.0 million. The $80.0 million was settled in full by applying the proceeds to the premiums on two new derivative contracts entered into as part of the hedge restructuring.

See Notes 2.e, 7 and 8.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report and "Item 3. Quantitative and Qualitative Disclosures About Market Risk" for additional information regarding our derivatives.

Income from equity method investee. See "—Results of operations - midstream and marketing" for a discussion of this income.

Interest expense. Interest expense decreased by $0.3 million and $1.3 million for the three and six months ended June 30, 2017, respectively, compared to the same periods in 2016. These decreases are primarily due to a lower outstanding balance on our Senior Secured Credit Facility.

Gain (loss) on disposal of assets, net. Gain (loss) on disposal of assets, net increased by $0.9 million for each of the three and six months ended June 30, 2017 compared to the same periods in 2016. From time to time, we dispose of materials and supplies inventory and other fixed assets. The associated gain or loss recorded during the period fluctuates depending upon the volume of the assets disposed, their associated net book value and, in the case of a disposal by sale, the sale price.

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Income tax. Since September 30, 2015, we have recorded a full valuation allowance against our net deferred tax position. As such, our effective tax rate was 0% during the three and six months ended June 30, 2017 and 2016. For further discussion of our income tax position, see Note 6 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.

Results of operations - midstream and marketing

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



	Three months ended June 30,					Six months ended June 30,
(in thousands)	2017		2016			2017		2016
Revenues:
Natural gas sales	$	825	$	—		$	1,641	$	—
Midstream service revenues	18,104		11,138			35,738		22,405
Sales of purchased oil	42,461		42,615			89,732		74,229
Total revenues	61,390		53,753			127,111		96,634
Costs and expenses:
Midstream service expenses	11,978		6,572			22,212		13,081
Costs of purchased oil	44,020		44,012			94,276		76,958
General and administrative⁽¹⁾	1,887		1,684			4,041		3,456
Depreciation and amortization⁽²⁾	2,320		2,208			4,635		4,394
Accretion of asset retirement obligations⁽³⁾	55		54			108		106
Operating income (loss)	$	1,130	$	(777	)	$	1,839	$	(1,361	)
Other financial information:
Income from equity method investee	$	2,471	$	3,696		$	5,539	$	5,994
Interest expense⁽⁴⁾	$	1,421	$	1,462		$	2,827	$	2,864

_______________________________________________________________________________

(1)

G&A expenses were allocated to the three months ended June 30, 2017 and 2016 based on the number of employees in the midstream and marketing segment as of June 30, 2017 and 2016, respectively, and were allocated to the three months ended March 31, 2017 and 2016 based on the number of employees in the midstream and marketing segment as of March 31, 2017 and 2016, respectively. Certain components of G&A expenses, primarily payroll, deferred compensation and vehicle expenses, were not allocated but were actual expenses for the segment. Land and geology expenses were not allocated to the 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 were allocated to the three months ended June 30, 2017 and 2016 based on the number of employees in the midstream and marketing segment as of June 30, 2017 and 2016, respectively, and were allocated to the three months ended March 31, 2017 and 2016 based on the number of employees in the midstream and marketing segment as of March 31, 2017 and 2016, respectively. Certain components of depreciation and amortization of other fixed assets, primarily vehicles, were not allocated but were actual expenses for the segment.


(3)	Accretion of asset retirement obligations were actual expenses and were not allocated.

(4)

Interest expense for the three months ended June 30, 2017 and March 31, 2017 was allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of June 30, 2017 and March 31, 2017, respectively. Interest expense for the three and six months ended June 30, 2016 was allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee as of June 30, 2016. Certain components of other fixed assets, primarily vehicles, were not allocated but were actual assets for the segment.

Natural gas sales. These revenues are related to our midstream and marketing segment providing our exploration and production segment with processed natural gas for use in the field. The corresponding cost component of these transactions are included in "Midstream service expenses." See Note 13 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information on our operating segments.

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Midstream service revenues. Our midstream service revenues increased by $7.0 million and $13.3 million, or 63% and 60%, for the three and six months ended June 30, 2017, respectively, compared to the same periods in 2016. These increases are mainly due to increased volume of water services provided.

Sales of purchased oil. Sales of purchased oil increased by $15.5 million, or 21%, for the six months ended June 30, 2017 compared to the same period in 2016 due to the increases in oil prices. For these sales of purchased oil, we purchase oil from third parties in West Texas, transport it on the Bridgetex Pipeline and sell it to a third party in the Houston market. The net loss for the six months ended June 30, 2017 compared to the same period in 2016 on this transaction has increased by $1.8 million, or 67%, mainly due to the relative strengthening of the Midland market.

Midstream service expenses. Midstream service expenses increased by $5.4 million and $9.1 million, or 82% and 70%, for the three and six months ended June 30, 2017, respectively, compared to the same periods in 2016. Midstream service expenses primarily represent costs incurred to operate and maintain our (i) oil and natural gas gathering and transportation systems and related facilities, (ii) centralized oil storage tanks, (iii) natural gas lift, rig fuel and centralized compression infrastructure and (iv) water storage, recycling and transportation facilities. These increases are due to the continued expansion of the midstream service component of our business.

Costs of purchased oil. Costs of purchased oil increased by $17.3 million, or 23%, for the six months ended June 30, 2017 compared to the same period in 2016 primarily due to the increases in oil prices. These costs include purchasing oil from third parties and transporting it on the Bridgetex Pipeline.

Income from equity method investee. We own 49% of the ownership units of Medallion. The third-party 51% interest-holder has initiated a process to potentially sell 100% of the ownership interests in Medallion within the next 12 months. We account 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."

Income from equity method investee decreased by $1.2 million and $0.5 million, or 33% and 8% for the three and six months ended June 30, 2017, respectively, compared to the same periods in 2016. The decreases are mainly due to increases in Medallion's depreciation, operating expenses and G&A expenses, partially offset by an increase in Medallion's transportation fee revenue resulting from higher throughput volumes. During the six months ended June 30, 2017, Medallion continued expansion activities on existing portions of its pipeline infrastructure in order to gather additional third-party oil production. The Medallion pipeline system transported an average of 169,105 barrels of oil per day ("BOPD") and 99,039 BOPD for the three months ended June 30, 2017 and 2016, respectively, and an average of 159,026 BOPD and 90,573 BOPD for the six months ended June 30, 2017 and 2016, respectively. See Note 2.h to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information regarding this investment.

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. See Notes 3 and 4 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our divestiture of oil and natural gas properties and debt, respectively.

The third-party 51% interest-holder has initiated a process to potentially sell 100% of the ownership interests in Medallion within the next 12 months. There can be no assurance that such potential sale will ultimately be consummated or, if consummated, the specific terms of such sale.

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We continually seek to maintain a financial profile that provides operational flexibility. As of August 7, 2017, we had $885.0 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 exploration and development activities. We use derivatives to reduce exposure to fluctuations in the prices of oil, NGL and natural gas.

See Note 7.a to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for information regarding our derivative settlement indices and our open hedge positions as of June 30, 2017. As of August 7, 2017, we have not entered into additional hedges subsequent to June 30, 2017.

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. 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, NGL and natural gas. See "Item 3. Quantitative and Qualitative Disclosures About Market Risk" below.

In January 2017, we completed the sale of 2,900 net acres and working interests in 16 producing vertical wells in the Midland Basin to a third-party buyer for a purchase price of $59.7 million. After transaction costs reflecting an economic effective date of October 1, 2016, the proceeds were $59.5 million, net of working capital and post-closing adjustments. We completed the closing adjustments for this divestiture in May 2017. A portion of these proceeds were used to pay down borrowings on our Senior Secured Credit Facility. The purchase price was recorded as an adjustment to oil and natural gas properties pursuant to the rules governing full cost accounting.

Cash flows

Our cash flows for the periods presented are summarized in the table below:



	Six months ended June 30,
(in thousands)	2017			2016
Net cash provided by operating activities	$	156,901		$	138,631
Net cash used in investing activities	(177,578		)	(243,630		)
Net cash provided by financing activities	23,029			93,154
Net increase (decrease) in cash and cash equivalents	$	2,352		$	(11,845	)

Cash flows from operating activities

Net cash provided by operating activities increased $18.3 million during the six months ended June 30, 2017 compared to the same period in 2016 mainly due to the price-related increase in oil, NGL and natural gas revenues; however, notable cash changes included (i) a decrease of $95.8 million in cash settlements received for matured and early terminations of derivatives, net of premiums paid, (ii) a cash outflow of $6.4 million related to the settlement of our last tranche of performance unit awards in first-quarter 2016 with no comparable amount incurred in the first or second quarter of 2017 and (iii) a decrease in working capital outflows of $1.3 million.

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, legislation and regulations 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 from investing activities

Net cash used in investing activities decreased $66.1 million during the six months ended June 30, 2017 compared to the same period in 2016 and is mainly attributable to (i) proceeds we received from a 2017 divestiture of oil and natural gas properties and (ii) a decrease in contributions made to Medallion partially offset by an increase in capital expenditures of oil and natural gas properties. See Note 3 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of the divestiture.

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



	Six months ended June 30,
(in thousands)	2017			2016
Capital expenditures:
Oil and natural gas properties	$	(232,219	)	$	(197,042	)
Midstream service assets	(6,117		)	(3,425		)
Other fixed assets	(2,683		)	(832		)
Investment in equity method investee	—			(42,681		)
Proceeds from dispositions of capital assets, net of selling costs	63,441			350
Net cash used in investing activities	$	(177,578	)	$	(243,630	)

Capital expenditure budget

Our board of directors approved a capital budget of approximately $530.0 million for calendar year 2017, excluding acquisitions and investments in Medallion. If upward pressure in service costs is sustained throughout the remainder of the year, an increase of 5% to 10% to our calendar year 2017 capital budget could result. We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted. In addition, as a 49% owner of Medallion, we do not direct the expansion activities of this entity and therefore cannot predict future capital commitments related to Medallion.

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, service costs, contractual obligations, internally generated cash flow and other factors both within and outside our control. For additional information on the impact of changing prices on our financial position, see "Item 3. Quantitative and Qualitative Disclosures About Market Risk."

Cash flows from financing activities

For the six months ended June 30, 2017, our net cash provided by financing activities was the result of borrowings on our Senior Secured Credit Facility partially offset by (i) payments on our Senior Secured Credit Facility, (ii) the purchase of treasury stock to satisfy employees' tax withholding upon vesting of their stock-based compensation awards and (iii) payments for debt issuance costs as a result of entering into the Fifth Amended and Restated Credit Agreement to our Senior Secured Credit Facility. The aforementioned increase in the purchase of treasury stock is mainly due to the increase of our stock price at the restricted stock awards' vest dates, which is utilized to determine the taxable compensation, compared to our stock price at the restricted stock awards' grant dates, which is utilized to determine the number of shares of restricted stock awards to be granted. For the 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.

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



	Six months ended June 30,
(in thousands)	2017			2016
Borrowings on Senior Secured Credit Facility	$	90,000		$	120,000
Payments on Senior Secured Credit Facility	(55,000		)	(144,682		)
Proceeds from issuance of common stock, net of offering costs	—			119,310
Purchase of treasury stock	(7,597		)	(1,541		)
Proceeds from exercise of employee stock options	358			67
Payments for debt issuance costs	(4,732		)	—
Net cash provided by financing activities	$	23,029		$	93,154

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Debt

As of June 30, 2017, we were a party only to our Senior Secured Credit Facility and the indentures governing our senior unsecured notes.

As of June 30, 2017, we had $1.4 billion in debt outstanding, $895.0 million available for borrowings under our Senior Secured Credit Facility and $35.0 million in cash on hand for total available liquidity of $930.0 million.

As of August 7, 2017, we had $1.4 billion in debt outstanding, $885.0 million available for borrowings under our Senior Secured Credit Facility and $12.0 million in cash on hand for total available liquidity of $897.0 million.

Senior Secured Credit Facility. As of June 30, 2017, our Senior Secured Credit Facility had a maximum credit amount of $2.0 billion, a borrowing base and an aggregate elected commitment each of $1.0 billion and $105.0 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. The maturity date of the Senior Secured Credit Facility is May 2, 2022, provided that if either of the January 2022 Notes or May 2022 Notes have not been redeemed or refinanced on or prior to the applicable Early Maturity Date, the Senior Secured Credit Facility will mature on such Early Maturity Date.

Principal amounts borrowed under our Senior Secured Credit Facility are payable on the final maturity date with such borrowings bearing interest that is payable, at our election, either on the last day of each fiscal quarter at an Adjusted Base Rate or at the end of one-, two-, three-, six- or, to the extent available, 12-month interest periods (and in the case of six- and 12-month interest periods, every three months prior to the end of such interest period) at an Adjusted London Interbank Offered Rate, in each case, plus an applicable margin, which ranges from 1.0% to 2.0% for Adjusted Base Rate loans and from 2.0% to 3.0% for Adjusted London Interbank Offered Rate loans, based on the ratio of the outstanding revolving credit on our Senior Secured Credit Facility to the elected commitment. We are also required to pay an annual commitment fee based on the unused portion of the bank's commitment of 0.375% to 0.5%.

Our Senior Secured Credit Facility is secured by a first-priority lien on certain of our assets, including oil and natural gas properties constituting at least 85% of the present value of our proved reserves owned now or in the future. Our Senior Secured Credit Facility contains both financial and non-financial covenants. We were in compliance with these covenants as of June 30, 2017.

Senior unsecured notes. The following table presents principal amounts and applicable interest rates for our outstanding senior unsecured notes as of June 30, 2017:



(in millions, except for interest rates)	Principal		Interest rate
January 2022 Notes	$	450.0	5.625	%
May 2022 Notes	500.0		7.375	%
March 2023 Notes	350.0		6.250	%
Total Senior Unsecured Notes	$	1,300.0

Refer to Note 4 of our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of the March 2023 Notes, January 2022 Notes, May 2022 Notes and our Senior Secured Credit Facility.

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Obligations and commitments

As of June 30, 2017, our contractual obligations included our March 2023 Notes, January 2022 Notes, May 2022 Notes, Senior Secured Credit Facility, drilling contract commitments, firm sale and transportation commitments, derivative deferred premiums, asset retirement obligations and office and equipment leases. From December 31, 2016 to June 30, 2017, the material changes in our contractual obligations included (i) a decrease of $59.2 million in our firm sale and transportation commitments, (ii) 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 2017, (iii) an increase of $35.0 million outstanding on our Senior Secured Credit Facility, (iv) a decrease of $5.6 million for drilling contract commitments (on contracts other than those on a well-by-well basis) and (v) an increase of $3.7 million in deferred premiums mainly due to new derivative contracts.

Refer to Notes 2, 4, 7, 8 and 11 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our contractual obligations.

Non-GAAP financial measure

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 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, impairment expense, non-cash stock-based compensation, net of amounts capitalized, accretion expense, mark-to-market on derivatives, cash premiums paid for derivatives, interest expense, write-off of debt issuance costs, gains or losses on disposal of assets, income or loss from equity method investee, proportionate Adjusted EBITDA of equity method investee and other non-recurring income and expenses. Adjusted EBITDA provides no information regarding a company’s capital structure, borrowings, interest costs, capital expenditures, working capital movement or tax position. Adjusted EBITDA does not represent funds available for 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.

During the year ended December 31, 2016, we changed the methodology for calculating Adjusted EBITDA by including adjustments for both accretion of asset retirement obligations and our proportionate share of our equity method investee's Adjusted EBITDA. Accordingly, the prior period's Adjusted EBITDA has been modified for comparability.

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



	Three months ended June 30,						Six months ended June 30,
(in thousands)	2017			2016			2017			2016
Net income (loss)	$	61,110		$	(71,432	)	$	129,386		$	(251,803	)
Plus:
Depletion, depreciation and amortization	38,003			34,177			72,115			75,655
Impairment expense	—			963			—			162,027
Non-cash stock-based compensation, net of amounts capitalized	8,687			6,073			17,911			9,911
Accretion expense	943			860			1,871			1,704
Mark-to-market on derivatives:
(Gain) loss on derivatives, net	(28,897		)	68,518			(65,568		)	50,633
Cash settlements received for matured derivatives, net	13,705			47,382			21,156			113,319
Cash settlements received for early terminations of derivatives, net	4,234			—			4,234			80,000
Cash premiums paid for derivatives	(9,987		)	(2,413		)	(12,094		)	(84,263		)
Interest expense	23,173			23,512			45,893			47,217
Write-off of debt issuance costs	—			842			—			842
(Gain) loss on disposal of assets, net	(805		)	141			(591		)	301
Income from equity method investee	(2,471		)	(3,696		)	(5,539		)	(5,994		)
Proportionate Adjusted EBITDA of equity method investee⁽¹⁾	6,601			5,103			12,966			8,787
Adjusted EBITDA	$	114,296		$	110,030		$	221,740		$	208,336

_______________________________________________________________________________


(1)	Proportionate Adjusted EBITDA of Medallion, our equity method investee, is calculated as follows:



	Three months ended June 30,				Six months ended June 30,
(in thousands)	2017		2016		2017		2016
Income from equity method investee	$	2,471	$	3,696	$	5,539	$	5,994
Adjusted for proportionate share of:
Depreciation and amortization	4,130		1,407		7,427		2,793
Proportionate Adjusted EBITDA of equity method investee	$	6,601	$	5,103	$	12,966	$	8,787

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Critical accounting policies and estimates

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

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

There have been no material changes in our critical accounting policies and procedures during the six months ended June 30, 2017. 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 2016 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 15 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for information regarding recent accounting pronouncements.

Off-balance sheet arrangements

Currently, we do not have any off-balance sheet arrangements other than operating leases, drilling contracts and firm sale and transportation commitments, which are described in "—Obligations and commitments." See Note 11 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information.

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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 call spreads 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 included elsewhere in this Quarterly Report.

The fair values of our derivatives are largely determined by estimates of the forward curves of the relevant price indices. As of June 30, 2017, 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	$	17,930	$	94,646

As of June 30, 2017 and December 31, 2016, the net fair values of our open derivative contracts were $55.1 million and $3.0 million, respectively. Refer to Notes 2.e, 7 and 8.a of our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional disclosures regarding our derivatives.

Interest rate risk

The expected maturity years, carrying amounts and fixed interest rates on our long-term debt as of June 30, 2017 and the Senior Secured Credit Facility's average floating interest rate for the six months ended June 30, 2017 were as follows:



	Expected maturity year
(in millions except for interest rates)	2022			2023
Senior Secured Credit Facility - floating rate	$	105.0		$	—
Average interest rate	2.614		%	—		%
January 2022 Notes - fixed rate	$	450.0		$	—
Interest rate	5.625		%	—		%
May 2022 Notes - fixed rate	$	500.0		$	—
Interest rate	7.375		%	—		%
March 2023 Notes - fixed rate	$	—		$	350.0
Interest rate	—		%	6.250		%

Counterparty and customer credit risk

As of June 30, 2017, our principal exposures to credit risk were through receivables of (i) $55.8 million from the fair values of our open derivative contracts, (ii) $45.5 million from sales of our oil, NGL and natural gas production that we market to energy marketing companies and refineries, (iii) $11.5 million from sales of purchased oil and other products, (iv) $9.0 million from joint-interest partners and (v) $6.0 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 purchased oil receivable with one customer. On occasion we require our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

We have entered into International Swap Dealers Association Master Agreements ("ISDA Agreements") with each of our derivative counterparties, each of whom is also a lender in our Senior Secured Credit Facility. The terms of the ISDA Agreements provide the non-defaulting or non-affected party the right to terminate the agreement upon the occurrence of certain events of default and termination events by a party and also provide for the marking to market of outstanding positions

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and the offset of the mark to market amounts owed to and by the parties (and in certain cases, the affiliates of the non-defaulting or non-affected party) upon termination.

Refer to Note 10 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, 2017. 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, 2017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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Part II

Item 1. Legal Proceedings

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

On May 3, 2017, Shell Trading (US) Company ("Shell") filed an Original Petition and Request for Disclosure in the District Court of Harris County, Texas, alleging that the crude oil purchase agreement entered into between Shell and Laredo effective October 1, 2016 does not reflect the compensation for Shell that Shell believes was previously agreed to by the parties due to a drafting mistake. Shell seeks reformation of one clause of the crude oil purchase agreement on the grounds of alleged mutual mistake or, in the alternative, unilateral mistake; an award of the amounts Shell alleges it should have been or should be paid under the agreement; court costs and attorneys’ fees. We do not believe there was a drafting mistake made in the crude oil purchase agreement. We believe we have substantive defenses and intend to vigorously defend our position. We are unable to determine the outcome or estimate our ultimate exposure, if any, to this litigation at this time.

Item 1A. Risk Factors

In addition to the other information set forth in this Quarterly Report, you should carefully consider the risks discussed in our 2016 Annual Report. There have been no material changes in our risk factors from those described in the 2016 Annual Report. The risks described in the 2016 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, 2017 - April 30, 2017	3,138	$	14.57	—	—
May 1, 2017 - May 31, 2017	3,107	$	12.09	—	—
June 1, 2017 - June 30, 2017	1,086	$	11.91	—	—
Total	7,331

______________________________________________________________________________


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

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

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 United States ("US") economic sanctions. Disclosure is generally required even where the activities, transactions or dealings were conducted in compliance with applicable law. Because the SEC defines the term "affiliate" broadly, it includes any entity under common "control" with us (and the term "control" is also construed broadly by the SEC).

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

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

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

(a) Santander UK plc ("Santander UK") holds two savings accounts and one current account for two customers resident in the United Kingdom ("UK") who are currently designated by the US under the Specially Designated Global Terrorist ("SDGT") sanctions program. Revenues and profits generated by Santander UK on these accounts in the six months ended June 30, 2017 were negligible relative to the overall revenues and profits of Banco Santander SA.

(b) Santander UK holds two frozen current accounts for two UK nationals who are designated by the US under the SDGT sanctions program. The accounts held by each customer have been frozen since their designation and have remained frozen through the six months ended June 30, 2017. The accounts are in arrears (£1,844.73 in debit combined) and are currently being managed by Santander UK Collections & Recoveries department. No revenues or profits were generated by Santander UK on this account in the six months ended June 30, 2017.

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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			Fifth Amended and Restated Credit Agreement, dated as of May 2, 2017, among Laredo Petroleum, Inc., as borrower, Wells Fargo Bank, National Association as administrative agent, and the other financial institutions signatory thereto (incorporated by reference to Exhibit 10.1 of Laredo's Quarterly Report on Form 10-Q (File No. 001-35380) filed on May 4, 2017).
31.1*			Certification of Chief Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
31.2*			Certification of Chief Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
32.1**			Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*			XBRL Instance Document.
101.SCH*			XBRL Schema Document.
101.CAL*			XBRL Calculation Linkbase Document.
101.DEF*			XBRL Definition Linkbase Document.
101.LAB*			XBRL Labels Linkbase Document.
101.PRE*			XBRL Presentation Linkbase Document.

______________________________________________________________________________

* Filed herewith.

** Furnished herewith.

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SIGNATURES

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



	LAREDO PETROLEUM, INC.

Date: August 8, 2017	By:	/s/ Randy A. Foutch
		Randy A. Foutch
		Chairman and Chief Executive Officer
		(principal executive officer)

Date: August 8, 2017	By:	/s/ Richard C. Buterbaugh
		Richard C. Buterbaugh
		Executive Vice President and Chief Financial Officer
		(principal financial officer)

Date: August 8, 2017	By:	/s/ Michael T. Beyer
		Michael T. Beyer
		Vice President - Controller and Chief Accounting Officer
		(principal accounting officer)

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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		Fifth Amended and Restated Credit Agreement, dated as of May 2, 2017, among Laredo Petroleum, Inc., as borrower, Wells Fargo Bank, National Association as administrative agent, and the other financial institutions signatory thereto (incorporated by reference to Exhibit 10.1 of Laredo's Quarterly Report on Form 10-Q (File No. 001-35380) filed on May 4, 2017).
31.1*		Certification of Chief Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
31.2*		Certification of Chief Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
32.1**		Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*		XBRL Instance Document.
101.SCH*		XBRL Schema Document.
101.CAL*		XBRL Calculation Linkbase Document.
101.DEF*		XBRL Definition Linkbase Document.
101.LAB*		XBRL Labels Linkbase Document.
101.PRE*		XBRL Presentation Linkbase Document.

______________________________________________________________________________

* Filed herewith.

** Furnished herewith.