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 ~~March 31,~~June 30, 2014

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

For the transition period from to

Commission File Number: 001-35380

Laredo Petroleum, Inc.

(Exact Name of Registrant as Specified in Its Charter)



Delaware (State or Other Jurisdiction of Incorporation or Organization)		45-3007926 (I.R.S. Employer Identification No.)



15 W. Sixth Street, Suite 900
Tulsa, Oklahoma		74119
(Address of Principal Executive Offices)		(Zip code)

(918) 513-4570

(Registrant’s Telephone Number, Including Area Code)

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

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

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



Large accelerated filer ý		Accelerated filer o

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

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

Number of shares of registrant’s common stock outstanding as of ~~May 5,~~August 4, 2014: ~~143,692,185~~143,762,444

TABLE OF CONTENTS



		Page
Cautionary Statement Regarding Forward-Looking Statements		iii
	Part I
Item 1.	Consolidated Financial Statements (Unaudited)	1
	Consolidated balance sheets as of ~~March 31,~~June 30, 2014 and December 31, 2013	1
	Consolidated statements of operations for the three and six months ended ~~March 31,~~June 30, 2014 and 2013	2
	Consolidated statement of stockholders’ equity for the ~~three~~six months ended ~~March 31,~~June 30, 2014	3
	Consolidated statements of cash flows for the ~~three~~six months ended ~~March 31,~~June 30, 2014 and 2013	4
	Condensed notes to the consolidated financial statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3032
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	4346
Item 4.	Controls and Procedures	4548
	Part II
Item 1.	Legal Proceedings	4649
Item 1A.	Risk Factors	4649
Item 2.	Repurchase of Equity Securities	4649
Item 3.	Defaults Upon Senior Securities	4649
Item 4.	Mine Safety Disclosures	4649
Item 5.	Other Information	4649
Item 6.	Exhibits	4751
Signatures		4852
Exhibit Index		4953

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. 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 recent instability and uncertainty in the U.S. and international financial and consumer markets that is adversely affecting the liquidity available to us and our customers and is adversely affecting the demand for commodities, including oil and natural gas;

volatility of oil and natural gas prices;

the possible introduction of regulations that prohibit or restrict our ability to apply hydraulic fracturing to our oil and natural gas wells;

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

the possible introduction of regulations that prohibit or restrict our ability to drill new allocation wells;

discovery, estimation, development and replacement of oil and natural gas reserves, including our expectations that estimates of our proved reserves will increase;

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

competition in the oil and natural gas industry;

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

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

risks related to the geographic concentration of our assets;

changes in domestic and global demand for oil and natural ~~gas, as well as~~ gas;

the continuation of restrictions on the export of domestic ~~crude oil;~~oil and its potential to cause weakness in domestic pricing;

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

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

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

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

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

evolving industry standards and adverse changes in global economic, political and other conditions;

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

our ability to access additional borrowing capacity under our Senior Secured Credit Facility or other means of providing liquidity; and

our ability to generate sufficient cash to service our indebtedness and to generate future profits.

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

iii

Financial Condition and Results of Operations", "Part II, Item 1A. Risk Factors" and elsewhere in this Quarterly Report, ~~and~~ under "Part I, Item 1A. Risk Factors" and "Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and

~~iii~~

Results of Operations" in our Annual Report on Form 10-K for the fiscal year ended December 31, 2013 (the "2013 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.

PART I

Item 1. Consolidated Financial Statements (Unaudited)

Laredo Petroleum, Inc.

Consolidated balance sheets

(in thousands, except share data)

(Unaudited)


	March 31, 2014			December 31, 2013			June 30, 2014			December 31, 2013
Assets
Current assets:
Cash and cash equivalents	$	547,519		$	198,153		$	399,506		$	198,153
Accounts receivable, net	80,937			77,318			95,720			77,318
Derivatives	3,946			15,806			1,360			15,806
Deferred income taxes	1,075			3,634			13,588			3,634
Other current assets	17,314			12,698			20,447			12,698
Total current assets	650,791			307,609			530,621			307,609
Property and equipment:
Oil and natural gas properties, full cost method:
Proved properties	3,432,647			3,276,578			3,698,051			3,276,578
Unproved properties not being amortized	255,892			208,085			225,056			208,085
Pipeline and gathering assets	57,726			44,255
Midstream service assets							80,265			51,704
Other fixed assets	42,936			40,281			42,016			32,832
Total property and equipment	3,789,201			3,569,199			4,045,388			3,569,199
Less accumulated depletion, depreciation, amortization and impairment	(1,414,423		)	(1,364,875		)	(1,467,172		)	(1,364,875		)
Net property and equipment	2,374,778			2,204,324			2,578,216			2,204,324
Derivatives	564			79,726			—			79,726
Deferred loan costs, net	32,398			25,933			31,088			25,933
Investment in equity method investee	22,803			5,913			40,871			5,913
Other assets, net	248			255			242			255
Total assets	$	3,081,582		$	2,623,760		$	3,181,038		$	2,623,760
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable	$	8,001		$	16,002		$	18,387		$	16,002
Accrued payable - affiliates	9,577			3,489			20,104			3,489
Undistributed revenue and royalties	34,072			35,124			44,122			35,124
Accrued capital expenditures	126,950			116,328			129,674			116,328
Derivatives	21,576			10,795			44,374			10,795
Other current liabilities	59,366			72,231			78,007			72,231
Total current liabilities	259,542			253,969			334,668			253,969
Long-term debt	1,501,479			1,051,538			1,501,419			1,051,538
Derivatives	5,324			2,680			36,317			2,680
Deferred income taxes	13,841			16,293			15,980			16,293
Asset retirement obligations	22,469			21,478			22,975			21,478
Other noncurrent liabilities	3,326			5,546			5,370			5,546
Total liabilities	1,805,981			1,351,504			1,916,729			1,351,504
Commitments and contingencies
Stockholders’ equity:
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued at March 31, 2014 and December 31, 2013	—			—
Common stock, $0.01 par value, 450,000,000 shares authorized, and 143,671,983 and 142,671,436 issued, net of treasury, at March 31, 2014 and December 31, 2013, respectively	1,437			1,427
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued at June 30, 2014 and December 31, 2013							—			—
Common stock, $0.01 par value, 450,000,000 shares authorized, and 143,737,390 and 142,671,436 issued, at June 30, 2014 and December 31, 2013, respectively							1,437			1,427
Additional paid-in capital	1,287,357			1,283,809			1,294,964			1,283,809
Accumulated deficit	(13,193		)	(12,980		)	(32,092		)	(12,980		)
Total stockholders’ equity	1,275,601			1,272,256			1,264,309			1,272,256
Total liabilities and stockholders’ equity	$	3,081,582		$	2,623,760		$	3,181,038		$	2,623,760

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

Laredo Petroleum, Inc.

Consolidated statements of operations

(in thousands, except per share data)

(Unaudited)


	Three months ended March 31,						Three months ended June 30,						Six months ended June 30,
	2014			2013			2014			2013			2014			2013
Revenues:
Oil and natural gas sales	$	173,214		$	163,625		$	182,872		$	177,048		$	356,086		$	340,673
Transportation and treating	96			80
Midstream service revenue							172			248			268			328
Total revenues	173,310			163,705			183,044			177,296			356,354			341,001
Costs and expenses:
Lease operating expenses	21,785			22,442			20,179			22,185			41,964			44,627
Production and ad valorem taxes	12,450			11,445			13,160			9,722			25,610			21,167
Transportation and treating	594			108
Transportation and treating - affiliates	516			—
Drilling and production	251			674
Midstream service expense							1,526			697			2,371			1,479
Natural gas volume commitment - affiliates							588			139			1,104			139
General and administrative	27,654			19,634			29,552			20,495			57,206			40,129
Accretion of asset retirement obligations	415			394			422			410			837			804
Depletion, depreciation and amortization	49,607			64,503			53,056			66,234			102,663			130,737
Total costs and expenses	113,272			119,200			118,483			119,882			231,755			239,082
Operating income	60,038			44,505			64,561			57,414			124,599			101,919
Non-operating income (expense):
Loss on derivatives:
Gain (loss) on derivatives:
Commodity derivatives, net	(31,112		)	(16,854		)	(63,125		)	23,975			(94,237		)	7,121
Interest rate derivatives, net	—			(6		)	—			(9		)	—			(15		)
Income (loss) from equity method investee	16			(64		)
Loss from equity method investee							(41		)	(49		)	(25		)	(113		)
Interest expense	(28,986		)	(25,349		)	(30,657		)	(25,943		)	(59,643		)	(51,292		)
Interest and other income	83			15			194			12			277			27
Write-off of deferred loan costs	(124		)	—			—			—			(124		)	—
Loss on disposal of assets, net	(21		)	—			(205		)	(59		)	(226		)	(59		)
Non-operating expense, net	(60,144		)	(42,258		)	(93,834		)	(2,073		)	(153,978		)	(44,331		)
Income (loss) from continuing operations before income taxes	(106		)	2,247			(29,273		)	55,341			(29,379		)	57,588
Income tax expense:
Income tax benefit (expense):
Deferred	(107		)	(1,110		)	10,374			(20,047		)	10,267			(21,157		)
Total income tax expense	(107		)	(1,110		)
Total income tax benefit (expense)							10,374			(20,047		)	10,267			(21,157		)
Income (loss) from continuing operations	(213		)	1,137			(18,899		)	35,294			(19,112		)	36,431
Income from discontinued operations, net of tax	—			272			—			518			—			790
Net income (loss)	$	(213	)	$	1,409		$	(18,899	)	$	35,812		$	(19,112	)	$	37,221
Net income (loss) per common share:
Basic:
Income (loss) from continuing operations	$	—		$	0.01		$	(0.13	)	$	0.28		$	(0.14	)	$	0.29
Income from discontinued operations, net of tax	—			—			—			—			—			0.01
Net income (loss) per share	$	—		$	0.01		$	(0.13	)	$	0.28		$	(0.14	)	$	0.30
Diluted:
Income (loss) from continuing operations	$	—		$	0.01		$	(0.13	)	$	0.27		$	(0.14	)	$	0.28
Income from discontinued operations, net of tax	—			—			—			—			—			0.01
Net income (loss) per share	$	—		$	0.01		$	(0.13	)	$	0.27		$	(0.14	)	$	0.29
Weighted-average common shares outstanding:
Basic	141,067			127,200			141,298			127,362			141,183			127,281
Diluted	141,067			128,851			141,298			129,384			141,183			129,119

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

Laredo Petroleum, Inc.

Consolidated statement of stockholders’ equity

(in thousands)

(Unaudited)


	Common Stock					Additional paid-in capital				Treasury Stock (at cost)						Accumulated deficit								Common Stock						Additional paid-in capital				Treasury Stock (at cost)						Accumulated deficit
	Shares		Amount						Shares			Amount				Accumulated deficit			Total				Shares			Amount				Additional paid-in capital			Shares			Amount				Accumulated deficit			Total
Balance, December 31, 2013	142,671		$	1,427		Additional paid-in capital	$	1,283,809			—			$	—		$	(12,980	)		$	1,272,256			142,671			$	1,427		$	1,283,809			—			$	—		$	(12,980	)		$	1,272,256
Restricted stock awards	1,068		10			(10		)		—			—			—				—				1,161			12			(12		)		—			—			—				—
Restricted stock forfeitures	(21	)	—			—				—			—			—				—				(50	)		(1		)	1				—			—			—				—
Vested restricted stock exchanged for tax withholding	—		—			—				127			(3,274		)	—				(3,274		)		—			—			—				136			(3,556		)	—				(3,556		)
Retirement of treasury stock	(127	)	(1		)	(3,273		)		(127	)		3,274			—				—				(136	)		(2		)	(3,554		)		(136	)		3,556			—				—
Exercise of employee stock options	80		1			1,584				—			—			—				1,585				91			1			1,828				—			—			—				1,829
Stock-based compensation	—		—			5,247				—			—			—				5,247				—			—			12,892				—			—			—				12,892
Net loss	—		—			—				—			—			(213		)		(213		)		—			—			—				—			—			(19,112		)		(19,112		)
Balance, March 31, 2014	143,671		$	1,437		$	1,287,357			—			$	—		$	(13,193	)		$	1,275,601
Balance, June 30, 2014																								143,737			$	1,437		$	1,294,964			—			$	—		$	(32,092	)		$	1,264,309

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

Laredo Petroleum, Inc.

Consolidated statements of cash flows

(in thousands)

(Unaudited)


	Three months ended March 31,						Six months ended June 30,
	2014			2013			2014			2013
Cash flows from operating activities:
Net income (loss)	$	(213	)	$	1,409		$	(19,112	)	$	37,221
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Deferred income tax expense	107			1,263
Deferred income tax (benefit) expense							(10,267		)	21,601
Depletion, depreciation and amortization	49,607			65,130			102,663			131,364
Non-cash stock-based compensation, net of amount capitalized	4,329			3,217			10,725			7,680
Accretion of asset retirement obligations	415			394			837			804
Mark-to-market on derivatives:
Loss on derivatives, net	31,112			16,860
(Gain) loss on derivatives, net							94,237			(7,106		)
Cash settlements (paid) received for matured derivatives, net	(1,431		)	3,676			(5,851		)	4,657
Cash settlements received for early terminations of derivatives, net	76,660			—			76,660			—
Change in net present value of deferred premiums paid for derivatives	65			151			120			282
Cash premiums paid for derivatives	(1,959		)	(2,422		)	(3,779		)	(5,249		)
Amortization of deferred loan costs	1,207			1,294			2,512			2,627
Write-off of deferred loan costs	124			—			124			—
Other	(47		)	16			145			74
Increase in accounts receivable	(3,619		)	(5,602		)	(18,402		)	(6,591		)
Increase in other assets	(4,616		)	(2,574		)	(7,749		)	(894		)
Decrease in accounts payable	(8,001		)	(18,523		)
Increase (decrease) in undistributed revenues and royalties	(1,052		)	3,524
Decrease in accrued compensation and benefits	(10,564		)	(4,221		)
Decrease in other accrued liabilities	(4,329		)	(792		)
Increase (decrease) in accounts payable							2,385			(16,568		)
Increase in undistributed revenues and royalties							8,998			4,327
Increase in other accrued liabilities							3,058			1,484
Increase in other noncurrent liabilities	224			162			1,644			422
Increase in fair value of performance unit awards	98			98			1,151			2,155
Net cash provided by operating activities	128,117			63,060			240,099			178,290
Cash flows from investing activities:
Capital expenditures:
Acquisition of oil and natural gas properties							(6,493		)	—
Acquisition of mineral interests	(7,305		)	—			(7,305		)	—
Investment in equity method investee	(11,300		)	(938		)	(19,471		)	(3,287		)
Oil and natural gas properties	(187,040		)	(187,813		)	(412,211		)	(375,901		)
Pipeline and gathering assets	(10,520		)	(4,046		)
Midstream service assets							(25,909		)	(8,302		)
Other fixed assets	(3,369		)	(6,588		)	(8,436		)	(8,803		)
Proceeds from dispositions of capital assets, net of costs	268			—			597			—
Net cash used in investing activities	(219,266		)	(199,385		)	(479,228		)	(396,293		)
Cash flows from financing activities:
Borrowings on revolving credit facilities	—			135,000			—			230,000
Issuance of January 2022 Notes	450,000			—			450,000			—
Purchase of treasury stock	(3,274		)	(875		)	(3,556		)	(919		)
Proceeds from exercise of employee stock options	1,585			—			1,829			—
Payments for loan costs	(7,796		)	—			(7,791		)	(714		)
Net cash provided by financing activities	440,515			134,125			440,482			228,367
Net increase (decrease) in cash and cash equivalents	349,366			(2,200		)
Net increase in cash and cash equivalents							201,353			10,364
Cash and cash equivalents, beginning of period	198,153			33,224			198,153			33,224
Cash and cash equivalents, end of period	$	547,519		$	31,024		$	399,506		$	43,588

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

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

A—Organization

Laredo Petroleum, Inc. ("Laredo" and formerly known as Laredo Petroleum Holdings, Inc.), together with its subsidiary, Laredo Midstream Services, LLC ("Laredo Midstream"), is an independent energy company focused on the exploration, development and acquisition of oil and natural gas properties primarily in the Permian Basin in West Texas. In these notes, the "Company," (i) when used in the present tense, prospectively or as of December 31, 2013, refers to Laredo and Laredo Midstream collectively; (ii) when used for historical periods prior to December 31, 2013, refers to Laredo and its subsidiaries, collectively. All amounts, dollars and percentages presented in these unaudited consolidated financial statements and the related notes are rounded and therefore approximate.

B—Basis of presentation and significant accounting policies

1. 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 Company uses the equity method of accounting to record its net interests when the Company holds 20% to 50% of the voting rights and/or has the ability to exercise significant influence but does not control the entity. Under the equity method, the Company's proportionate share of the investee's net income (loss) is included in the unaudited consolidated statements of operations. See Note L for additional discussion of the Company's equity method investment. 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 ~~operates oil and natural gas properties~~reports as one business segment, which explores for, develops and produces oil and natural gas. Unless otherwise indicated, the information in these notes relate to the Company’s continuing operations.

The accompanying consolidated financial statements have not been audited by the Company’s independent registered public accounting firm, except that the consolidated balance sheet at December 31, 2013 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 ~~March 31,~~June 30, 2014, results of operations for the three and six months ended June 30, 2014 and ~~the results of operations~~2013 and cash flows for the ~~three~~six months ended ~~March 31,~~June 30, 2014 and 2013.

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 Laredo’s Annual Report on Form 10-K for the year ended December 31, 2013 (the "2013 Annual Report").

2. 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 from these estimates. 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 and natural gas, (ii) future cash flows from oil and natural gas properties, (iii) depletion, depreciation and amortization, (iv) asset retirement obligations, (v) stock-based compensation, (vi) deferred income taxes, (vii) fair value of assets acquired and liabilities assumed in an acquisition and (viii) fair values of commodity derivatives, interest rate derivatives, commodity deferred premiums, performance share awards and performance unit awards. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. 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

~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

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.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

3. Reclassifications

Certain amounts in the accompanying unaudited consolidated financial statements have been reclassified to conform to the 2014 presentation. These reclassifications had no impact to previously reported net income ~~or losses,~~(loss), total stockholders' equity or cash flows.

4. Treasury stock

The Company acquires treasury stock, which is recorded at cost, to satisfy tax withholding obligations for Laredo's employees that arise upon the lapse of restrictions on restricted ~~stock or for other reasons.~~stock. Upon acquisition, this treasury stock is retired.

5. Accounts receivable

The Company sells oil and natural gas to various customers and participates with other parties in the drilling, completion and operation of oil and natural gas wells. Joint interest and oil and natural gas sales receivables related to these operations are generally unsecured. Accounts receivable for joint interest billings are recorded as amounts billed to customers less an allowance for doubtful accounts.

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

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


(in thousands)	March 31, 2014		December 31, 2013		June 30, 2014		December 31, 2013
Oil and natural gas sales	$	58,086	$	57,647	$	68,476	$	57,647
Joint operations, net⁽¹⁾	20,773		16,629		23,274		16,629
Other	2,078		3,042		3,970		3,042
Total	$	80,937	$	77,318	$	95,720	$	77,318


(1)	Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.7 million as of ~~each of March 31,~~June 30, 2014 and December 31, 2013.

6. Derivatives

The Company uses derivatives to reduce its exposure to fluctuations in the prices of oil 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 primarily in the form of collars, swaps, puts and basis swaps. In addition, in prior periods the Company entered into derivative contracts in the form of interest rate derivatives to minimize the effects of fluctuations in interest rates.

Derivatives are recorded at fair value and are included on the unaudited consolidated balance sheets as assets or liabilities. The Company ~~netted~~nets the fair value of derivatives by counterparty in the accompanying unaudited consolidated balance sheets 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.

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 Note G).

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

7. Property and equipment

The following table sets forth the Company’s property and equipment for the periods presented:


(in thousands)	March 31, 2014		December 31, 2013		June 30, 2014			December 31, 2013
Proved oil and natural gas properties	$	3,432,647	$	3,276,578	$	3,698,051		$	3,276,578
Less accumulated depletion and impairment	1,397,058		1,349,315		(1,448,013		)	(1,349,315		)
Proved oil and natural gas properties, net	2,035,589		1,927,263		2,250,038			1,927,263

Unproved properties not being amortized	255,892		208,085		225,056			208,085

Pipeline and gathering assets	57,726		44,255
Midstream service assets					80,265			51,704
Less accumulated depreciation	3,343		2,757		(6,007		)	(4,404		)
Pipeline and gas gathering assets, net	54,383		41,498
Midstream service assets, net					74,258			47,300

Other fixed assets	42,936		40,281		42,016			32,832
Less accumulated depreciation and amortization	14,022		12,803		(13,152		)	(11,156		)
Other fixed assets, net	28,914		27,478		28,864			21,676

Total property and equipment, net	$	2,374,778	$	2,204,324	$	2,578,216		$	2,204,324

For the three months ended ~~March 31,~~June 30, 2014 and 2013, depletion expense was $~~19.61~~19.55 per barrel of oil equivalent ("BOE") and ~~$20.25~~$20.08 per BOE, respectively. For the six months ended June 30, 2014 and 2013, depletion expense was $19.58 per BOE and $20.16 per BOE, respectively.

8. Deferred loan costs

Loan origination fees, which are stated 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 $7.8 million of deferred loan costs during the ~~three~~six months ended ~~March 31,~~June 30, 2014 mainly as a result of the issuance of the January 2022 Notes (as defined below). NoThe Company capitalized $0.7 million of deferred loan costs ~~were capitalized~~ during the ~~three~~six months ended ~~March 31,~~June 30, 2013. The Company had total deferred loan costs of ~~$32.4~~$31.1 million and $25.9 million, net of accumulated amortization of $~~15.4~~16.7 million and $14.2 million, as of ~~March 31,~~June 30, 2014 and December 31, 2013, respectively.

As a result of changes in the borrowing base of the Senior Secured Credit Facility (as defined below) due to the issuance of the January 2022 Notes, the Company wrote-off ~~approximately~~ $0.1 million in deferred loan costs during the ~~three~~six months ended ~~March 31,~~June 30, 2014. No deferred loan costs were written-off during the ~~three~~six months ended ~~March 31,~~June 30, 2013.

Future amortization expense of deferred loan costs as of ~~March 31,~~June 30, 2014 is as follows:


(in thousands)
Remaining 2014	$	3,927	$	2,627
2015	5,289		5,295
2016	5,355		5,361
2017	5,427		5,432
2018	5,219		5,222
Thereafter	7,181		7,151
Total	$	32,398	$	31,088

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

9. Other current liabilities

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


(in thousands)	March 31, 2014		December 31, 2013		June 30, 2014		December 31, 2013
Accrued interest payable	$	26,893	$	25,885	$	37,065	$	25,885
Accrued compensation and benefits					11,804		16,711
Lease operating expense payable	12,159		10,637		11,056		10,637
Accrued compensation and benefits	6,147		16,711
Performance unit awards	2,487		—		2,971		—
Asset retirement obligations					886		265
Prepaid drilling liability	802		1,393		851		1,393
Asset retirement obligations	264		265
Other accrued liabilities	10,614		17,340		13,374		17,340
Total other current liabilities	$	59,366	$	72,231	$	78,007	$	72,231

10. Asset retirement obligations

Asset retirement obligations associated with the retirement of tangible long-lived assets are recognized as a liability in the period in which they are incurred and become determinable. The associated asset retirement costs are part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related long-lived asset is charged to expense through the depletion of the 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 based on the reserve life per well; (iii) future inflation factors; and (iv) 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 gas gathering assets and perform other remediation of the sites where such pipeline and gas 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 gas gathering assets in the periods in which settlement dates become reasonably determinable.

The following reconciles the Company’s asset retirement obligation liability for continuing and discontinued operations for the periods presented:



(in thousands)	Six months ended June 30, 2014			Year ended December 31, 2013
Liability at beginning of period	$	21,743		$	21,505
Liabilities added due to acquisitions, drilling and other	1,591			2,709
Accretion expense	837			1,475
Liabilities settled upon plugging and abandonment	(310		)	(226		)
Liabilities removed due to Anadarko Basin Sale⁽¹⁾	—			(7,801		)
Revision of estimates	—			4,081
Liability at end of period	$	23,861		$	21,743


(1)	See Note C.3 for definition of and information regarding the Anadarko Basin Sale.

(in thousands) Three months ended March 31, 2014 Year ended December 31, 2013
Liability at beginning of period $ 21,743
$ 21,505
Liabilities added due to acquisitions, drilling and other 576
2,709
Accretion expense 415
1,475
Liabilities settled upon plugging and abandonment (1 ) (226 )
Liabilities removed due to Anadarko Basin Sale —
(7,801 )
Revision of estimates —
4,081
Liability at end of period $ 22,733
$ 21,743

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

11. Fair value measurements

The carrying amounts reported in the unaudited consolidated balance sheets for cash and cash equivalents, accounts receivable, prepaid expenses, accounts payable, undistributed revenue and royalties and other accrued liabilities approximate their fair values. See Note D for fair value disclosures related to the Company’s debt obligations. The Company carries its derivatives at fair value. See Note G and Note H for details regarding the fair value of the Company’s derivatives.

~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

12. Compensation awards

~~For stock-based compensation awards,~~Stock-based compensation expense is recognized in "General and administrative" in the Company’s unaudited consolidated statements of operations over the awards’ vesting periods and is based on their grant date fair value. The Company utilizes the closing stock price on the date of grant, less an expected forfeiture rate, to determine the fair value of service vesting restricted stock awards and a Black-Scholes pricing model to determine the fair values of service vesting restricted stock option awards. The Company utilizes a Monte Carlo simulation prepared by an independent third party to determine the fair values of the performance share awards and performance unit awards. ~~During the three months ended March 31,~~On January 1, 2014, the Company began capitalizing a portion of stock-based compensation for employees who are directly involved in the acquisition and exploration ~~and development~~ of ~~our~~its 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 E for further discussion ofregarding the restricted stock awards, restricted stock option awards, performance share awards and performance unit awards.

13. 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. All environmental expenditures, including expenditures that relate to an existing condition caused by past operations and that have no future economic benefits, are expensed in the period in which they occur. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. Management believes no materially significant liabilities of this nature existed as of ~~March 31,~~June 30, 2014 or December 31, 2013.

14. Supplemental cash flow disclosure information and non-cash investing and financing information

The following table summarizes the supplemental disclosure of cash flow information for the periods presented:


	Three months ended March 31,				Six months ended June 30,
(in thousands)	2014		2013		2014		2013
Cash paid for interest, net of $0 and $95 of capitalized interest, respectively	$	26,849	$	27,649
Cash paid for interest, net of $0 and $212 of capitalized interest, respectively					$	46,140	$	48,348

The following presents the supplemental disclosure of non-cash investing and financing information for the periods presented:


	Three months ended March 31,					Six months ended June 30,
(in thousands)	2014		2013			2014		2013
Change in accrued capital expenditures	$	10,622	$	(22,680	)	$	13,346	$	(33,892	)
Capitalized asset retirement cost	$	576	$	615		$	1,591	$	1,262
Capitalized stock-based compensation	$	918	$	—		$	2,167	$	—
Restricted deposits on pending sale						$	—	$	44,000

C—~~Acquisition~~Acquisitions and divestiture

1. 2014 acquisition of mineral interests

On February 25, 2014, the Company completed the acquisition of the mineral interests underlying 278 net acres in Glasscock County, Texas in the Permian Basin for $7.3 million. ~~The~~These mineral interests entitle the Company to receive royalty ~~interest~~interests on all production from ~~this acreage~~these acreages with no additional future capital or operating ~~expense~~expenses required. As such, the acquisition was accounted for as an acquisition of assets.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

2. 2014 acquisitions of proved and unproved oil and natural gas properties

The Company accounts for acquisitions of proved and unproved 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 and integration 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 values of proved and unproved oil and natural gas properties. The fair values of these properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The market-based weighted average cost of capital rate is subject to additional project-specific risk factors. To compensate for the inherent risk of estimating the value of the unproved properties, the discounted future net revenues of probable and possible reserves are reduced by additional risk-weighting factors.

On June 11, 2014, the Company completed the acquisition of proved and unproved oil and natural gas properties, totaling 460 net acres, located in Reagan County, Texas for $4.7 million, net of closing adjustments. On June 23, 2014, the Company completed the acquisition of proved and unproved oil and natural gas properties, totaling 24 net acres, located in Glasscock County, Texas for $1.8 million. The results of operations prior to June 2014 do not include results from these acquisitions.

3. 2013 divestiture of Anadarko assets

On August 1, 2013, the Company completed the sale of its oil and natural gas properties, associated pipeline assets and various other related property and equipment in the Anadarko Granite Wash, Central Texas Panhandle and the Eastern Anadarko Basin (the "Anadarko Basin Sale") to certain affiliates of EnerVest, Ltd. (collectively, "EnerVest") and certain other third parties in connection with the exercise of such third parties' preferential rights associated with the oil and natural gas assets. The purchase price consisted of $400.0 million from EnerVest and $38.0 million from the third parties. $388.0 million of the

~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

purchase price, excluding closing adjustments, was allocated to oil and natural gas properties pursuant to the rules governing full cost accounting. After transaction costs and adjustments at closing reflecting an economic effective date of April 1, 2013, the net proceeds were $428.3 million, net of working capital adjustments.

Effective at closing, the operations and cash flows of these properties were eliminated from the ongoing operations of the Company and the Company does not have continuing involvement in the operations of these properties. The results of operations of the oil and natural gas properties that are a component of the Anadarko Basin Sale are not presented as discontinued operations pursuant to the rules governing full cost accounting for oil and natural gas properties.

The following table presents revenues and operating expenses of the oil and natural gas properties that are a component of the Anadarko Basin Sale included in the accompanying unaudited consolidated statements of operations for the ~~period~~periods presented:


(in thousands)	Three months ended March 31, 2013		Three months ended June 30, 2013		Six months ended June 30, 2013
Revenues	$	23,602	$	26,135	$	49,737
Expenses⁽¹⁾	20,919		19,918		40,837


(1)	Expenses include lease operating expense, production and ad valorem tax expense, accretion expense and depletion, depreciation and amortization expense.

For the three and six months ended ~~March 31,~~June 30, 2013, the results of operations of the associated pipeline assets and various other related property and equipment ("Pipeline Assets") are presented as results of discontinued operations, net of tax in these unaudited consolidated financial statements. As a result of the sale of the Pipeline Assets, a gain of $3.2 million was recognized in the consolidated statements of operations for the year ended December 31, 2013 in the line item "Loss on disposal of assets, net."

~~The following represents operating results from discontinued operations for the period presented:~~

(in thousands) Three months ended March 31, 2013
Revenues:
Transportation and treating $ 1,832
Total revenues from discontinued operations 1,832
Cost and expenses:
Transportation and treating 536
Drilling and production 244
Depletion, depreciation and amortization 627
Total costs and expenses from discontinued operations 1,407
Income from discontinued operations before income tax 425
Income tax expense (153 )
Income from discontinued operations $ 272

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The following represents operating results from discontinued operations for the periods presented:



(in thousands)	Three months ended June 30, 2013			Six months ended June 30, 2013
Revenues:
Midstream service revenue	$	1,478		$	3,310
Total revenues from discontinued operations	1,478			3,310
Cost and expenses:
Midstream service expense	669			1,449
Depletion, depreciation and amortization	—			627
Total costs and expenses from discontinued operations	669			2,076
Income from discontinued operations before income tax	809			1,234
Income tax expense	(291		)	(444		)
Income from discontinued operations	$	518		$	790

D—Debt

1. Interest expense

The following amounts have been incurred and charged to interest expense for the periods presented:


	Three months ended March 31,					Three months ended June 30,					Six months ended June 30,
(in thousands)	2014		2013			2014		2013			2014		2013
Cash payments for interest	$	26,849	$	27,744		$	19,291	$	20,816		$	46,140	$	48,560
Amortization of deferred loan costs and other adjustments	1,129		1,304			1,194		1,320			2,323		2,624
Change in accrued interest	1,008		(3,604		)	10,172		3,924			11,180		320
Interest costs incurred	28,986		25,444			30,657		26,060			59,643		51,504
Less capitalized interest	—		(95		)	—		(117		)	—		(212		)
Total interest expense	$	28,986	$	25,349		$	30,657	$	25,943		$	59,643	$	51,292

2. 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"), and entered into an Indenture (the "Indenture") among Laredo, Laredo Midstream as guarantor and Wells Fargo Bank, National Association, as trustee. The January 2022 Notes will mature on January 15, 2022 with interest accruing at a rate of 5 5/8% per annum and 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 guaranteed on a senior unsecured basis by Laredo Midstream and certain of the Company’s future restricted subsidiaries.

The January 2022 Notes were issued pursuant to the Indenture in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended (the "Securities Act"). The January 2022 Notes were offered and sold only to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act. The Company received net proceeds of $442.2 million from the offering, after deducting the initial purchasers’ discount and the estimated outstanding offering expenses. The Company ~~will use~~is using the net proceeds of the offering for general working capital purposes.

The Company may redeem, at its option, all or part of the January 2022 Notes at any time on and after January 15, 2017, at the applicable redemption price plus accrued and unpaid interest to the date of redemption. In addition, the Company may redeem, at its option, all or part of the January 2022 Notes at any time prior to January 15, 2017 at a redemption price equal to 100% of the principal amount of the January 2022 Notes redeemed plus the applicable premium and accrued and unpaid interest and additional interest, if any, to the date of redemption. Further, before January 15, 2017, the Company may on one or more occasions redeem up to 35% of the aggregate principal amount of the January 2022 Notes in an amount not exceeding the net proceeds from one or more private or public equity offerings at a redemption price of 105.625% of the principal amount of the January 2022 Notes, plus accrued and unpaid interest to the date of redemption, if at least 65% of the aggregate principal amount of the January 2022 Notes remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of each such equity offering. If a change of control occurs prior to January 15, 2015, the Company may redeem all, but not less than all, of the January 2022 Notes at a redemption price equal to 110% of the principal amount of the January 2022 Notes plus any accrued and unpaid interest to the date of redemption.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

In connection with the closing of the offering of the January 2022 Notes, the Company entered into a registration rights agreement with the several initial purchasers named in the registration rights agreement, pursuant to which the Company filed a registration statement with the Securities and Exchange Commission ("SEC") that became effective with respect to an offer to exchange the January 2022 Notes for substantially identical notes (other than with respect to restrictions on transfer or any increase in annual interest rate) that are registered under the Securities Act. The offer to exchange the January 2022 Notes for substantially identical notes registered under the Securities Act ~~commenced~~was launched on April 22, 2014 ~~and is scheduled to expire~~with all notes exchanged on May ~~21, 2014, unless extended. There is no guarantee the Company will be successful in exchanging any or all of the January 2022 Notes.~~22, 2014.

3. 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 Laredo ~~Midstream.~~Midstream and certain of the Company’s future restricted subsidiaries.

~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

4. 2019 Notes

On January 20, 2011, the Company completed an offering of $350.0 million 9 1/2% senior unsecured notes due 2019 (the "January Notes") and on October 19, 2011, the Company completed an offering of an additional $200.0 million 9 1/2% senior unsecured notes due 2019 (the "October Notes" and together with the January Notes, the "2019 Notes"). The 2019 Notes will mature on February 15, 2019 and bear an interest rate of 9 1/2% per annum, payable semi-annually, in cash in arrears on February 15 and August 15 of each year. The 2019 Notes are fully and unconditionally guaranteed on a senior unsecured basis by Laredo ~~Midstream.~~Midstream and certain of the Company’s future restricted subsidiaries.

5. Senior Secured Credit Facility

As of ~~March 31,~~June 30, 2014, the Fourth Amended and Restated Credit Agreement (as amended, the "Senior Secured Credit Facility") ~~had a maturity date of~~, which matures on November 4, 2018, ~~and~~had a borrowing base of $1.0 billion and an aggregate elected commitment of $~~812.5~~825.0 million with no amounts outstanding. It contains both financial and non-financial covenants, all of which the Company was in compliance with as of ~~March 31,~~June 30, 2014. 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.

~~Subsequent to March 31,~~ On August 5, 2014, ~~the Company entered into an amendment to~~there were no amounts outstanding on the Senior Secured Credit Facility. ~~See Note O.1 for additional information.~~

6. Fair value of debt

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


	March 31, 2014				December 31, 2013				June 30, 2014				December 31, 2013
(in thousands)	Carrying value		Fair value		Carrying value		Fair value		Carrying value		Fair value		Carrying value		Fair value
2019 Notes⁽¹⁾	$	551,479	$	612,278	$	551,538	$	615,313	$	551,419	$	599,500	$	551,538	$	615,313
January 2022 Notes	450,000		456,471		—		—		450,000		465,750		—		—
May 2022 Notes	500,000		556,250		500,000		549,375		500,000		561,250		500,000		549,375
Total value of debt	$	1,501,479	$	1,624,999	$	1,051,538	$	1,164,688	$	1,501,419	$	1,626,500	$	1,051,538	$	1,164,688


(1)	The carrying value of the 2019 Notes includes the October Notes unamortized bond premium of $~~1.5~~1.4 million ~~at each~~and $1.5 million as of ~~March 31,~~June 30, 2014 and December 31, ~~2013.~~2013, respectively.

The fair values of the debt outstanding on the 2019 Notes, the January 2022 Notes and the May 2022 Notes were determined using the ~~March 31,~~June 30, 2014 and December 31, 2013 quoted market price (Level 1)~~, respectively.~~ for each respective instrument. See Note H for information about fair value hierarchy levels.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

E—Employee compensation

The Company has a Long-Term Incentive Plan (the "LTIP"), which provides for the granting of incentive awards in the form of restricted stock awards, restricted stock options awards, performance share awards, performance unit awards and other awards. The LTIP provides for the issuance of 10.0 million shares.

The Company recognizes the fair value of stock-based compensation granted to employees and directors 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. Stock-based compensation is included in "General and administrative" in the unaudited consolidated statements of operations. ~~During the three months ended March 31,~~On January 1, 2014, the Company began capitalizing a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration and development of ~~our~~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.

1. Restricted stock awards

All restricted stock awards are treated as issued and outstanding in the accompanying unaudited consolidated financial statements. If an employee terminates employment prior to the restriction lapse date, the awarded shares are forfeited and

~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

canceled and are no longer considered issued and outstanding. If the employee's termination of employment is by reason of death or disability, ~~then~~ all of the holder's restricted stock will automatically vest. Restricted stock awards granted to officers and employees vest in a variety of vesting schedules including (i) 20% at the grant date and then vest 20% annually thereafter; (ii) 33%, 33% and 34% per year beginning on the first anniversary date of the grant; (iii) 50% in year two and 50% in year three; (iv) fully on the first anniversary date of the grant and (v) fully on the third anniversary date of the grant. Restricted stock awards granted to non-employee directors vest fully on the first anniversary date of the grant.

The following table reflects the outstanding restricted stock awards for the ~~three~~six months ended ~~March 31,~~June 30, 2014:


(in thousands, except for weighted-average grant date fair values)	Restricted stock awards		Weighted-average grant date fair value		Restricted stock awards		Weighted-average grant date fair value (per award)
Outstanding at December 31, 2013	1,799		$	19.17	1,799		$	19.17
Granted	1,068		$	25.63	1,161		$	25.75
Forfeited	(21	)	$	22.75	(50	)	$	22.62
Vested⁽¹⁾	(402	)	$	17.90	(527	)	$	17.70
Outstanding at March 31, 2014	2,444		$	22.19
Outstanding at June 30, 2014					2,383		$	22.64

(1)

The vesting of certain restricted stock ~~grants~~awards could result in federal and state income tax expense or benefits related to the difference between the market price of the common stock at the date of vesting and the date of grant. For the three and six months ended ~~March 31,~~June 30, 2014, the Company's recognized income tax expense related to the vesting of restricted stock awards was immaterial. The Company recognized income tax expense of ~~$0.3~~$0.1 million and $0.4 million during the three and six months ended ~~March 31,~~June 30, 2013, respectively, related to restricted stock awards, which were recorded as adjustments to deferred income taxes.

The Company utilizes the closing stock price on the date of grant to determine the fair value of service vesting restricted stock awards. As of ~~March 31,~~June 30, 2014, unrecognized stock-based compensation related to the restricted stock awards was ~~$43.6~~$39.5 million. Such cost is expected to be recognized over a weighted-average period of ~~2.09~~1.91 years.

2. Restricted stock option awards

Restricted stock ~~options~~option awards granted under the LTIP vest and are exercisable in four equal installments on each of the ~~first~~ four anniversaries of the date of the grant. The following table reflects the stock option award activity for the ~~three~~six months ended ~~March 31,~~June 30, 2014:


(in thousands, except for weighted-average exercise price and contractual term)	Restricted stock option awards		Weighted-average exercise price (per option)		Weighted-average remaining contractual term (years)	Restricted stock option awards		Weighted-average exercise price (per option)		Weighted-average remaining contractual term (years)
Outstanding at December 31, 2013	1,229		$	19.32	8.82	1,229		$	19.32	8.82
Granted	336		$	25.60	9.91	336		$	25.60	9.66
Exercised⁽¹⁾	(80	)	$	19.92	8.49	(91	)	$	20.02	8.22
Expired or canceled	—		$	—	—	—		$	—	—
Forfeited	(12	)	$	19.61	—	(13	)	$	19.61	—
Outstanding at March 31, 2014	1,473		$	20.72	8.89
Outstanding at June 30, 2014						1,461		$	20.72	8.64
Vested and exercisable at end of period⁽²⁾	367		$	20.36	8.42	355		$	20.35	8.17
Vested, exercisable, and expected to vest at end of period⁽³⁾	1,440		$	20.71	8.88	1,428		$	20.71	8.64

(1)

The exercise of stock ~~options~~option awards could result in federal and state income tax expense or benefits related to the difference between the fair value of the stock option at the date of grant and the intrinsic value of the stock option when exercised. The Company recognized income tax expense of $0.1 million and $0.2 million during the three and six months ended ~~March 31,~~June 30, 2014, respectively, related to stock options, which were recorded as adjustments to deferred income taxes. No stock options were exercised during the three and six months ended ~~March 31,~~June 30, 2013.


(2)	The aggregate intrinsic value of vested and exercisable options at ~~March 31,~~June 30, 2014 was ~~$2.0~~$3.8 million.


(3)	The aggregate intrinsic value of vested, exercisable and expected to vest options at ~~March 31,~~June 30, 2014 was ~~$7.4~~$14.7 million.

The Company ~~utilized~~utilizes the Black-Scholes option pricing model to determine the fair ~~value~~values of restricted stock ~~options~~option awards and is recognizing 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 ~~options~~

~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

option awards will be outstanding prior to exercise and the associated volatility. As of ~~March 31,~~June 30, 2014 unrecognized stock-based compensation related to the restricted option awards was ~~$11.7~~$10.7 million. Such cost is expected to be recognized over a weighted-average period of ~~3.04~~2.79 years.

The assumptions used to estimate the fair value of restricted stock options granted on February 27, 2014 are as follows:



Risk-free interest rate⁽¹⁾	1.88		%
Expected option life⁽²⁾	6.25 years
Expected volatility⁽³⁾	53.21		%
Fair value per stock option	$	13.41


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


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


(3)	The Company utilized a peer historical look-back, which was weighted with the Company’s own volatility, in order to develop the expected volatility.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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



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

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

3. Performance share awards

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

The ~~2014 performance share awards~~Performance Share Awards have a performance period of January 1, 2014 to December 31, 2016 and any shares earned under such awards are expected to be issued in the first quarter of 2017 if the performance criteria is met. During the ~~three~~six months ended ~~March 31,~~June 30, 2014, 271,667 performance shares were awarded and all remain outstanding at ~~March 31,~~June 30, 2014. As of ~~March 31,~~June 30, 2014, unrecognized stock-based compensation related to the ~~performance share awards~~Performance Share Awards was ~~$7.3~~$6.7 million. Such cost is expected to be recognized over a weighted-average period of ~~2.91~~2.66 years.

~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

The assumptions used to estimate the fair value of the ~~performance share awards granted on February 27, 2014~~Performance Share Awards are as follows:


Risk-free rate⁽¹⁾	0.63		%	0.63		%
Dividend yield	—		%	—		%
Expected volatility⁽²⁾	38.21		%	38.21		%
Laredo closing price as of February 27, 2014	$	25.60
Laredo stock closing price as of February 27, 2014				$	25.60
Fair value per performance share	$	28.56		$	28.56


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


(2)	The Company utilized a peer historical look-back, weighted with the Company's own volatility, to develop the expected volatility.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

4. Stock-based compensation award expense

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


	Three months ended March 31,					Three months ended June 30,					Six months ended June 30,
(in thousands)	2014			2013		2014			2013		2014			2013
Restricted stock award compensation	$	4,232		$	2,826	$	6,010		$	3,572	$	10,242		$	6,398
Restricted stock option award compensation	795			391		1,010			891		1,805			1,282
Restricted performance share unit award compensation	220			—		625			—		845			—
Total stock-based compensation	5,247			3,217		7,645			4,463		12,892			7,680
Less amounts capitalized in oil and natural gas properties	(918		)	—		(1,249		)	—		(2,167		)	—
Net stock-based compensation expense	$	4,329		$	3,217	$	6,396		$	4,463	$	10,725		$	7,680

5. Performance unit awards

The performance unit awards issued to management on February 15, 2013 ("2013 ~~performance unit awards"~~Performance Unit Awards") and on February 3, 2012 ("2012 ~~performance unit awards"~~Performance Unit Awards") are subject to a combination of market and service vesting criteria. A Monte Carlo simulation prepared by an independent third party is utilized in order to determine the fair value of these awards at the date of grant and to re-measure the fair value at the end of each reporting period until settlement in accordance with GAAP. The volatility criteria utilized in the Monte Carlo simulation is based on the volatility of the ~~Company~~Company's stock price and the stock price volatilities of a group of peer companies that have been determined to be most representative of the Company’s expected volatility. These awards are accounted for as liability awards as they will be settled in cash at the end of the requisite service period based on the achievement of certain performance criteria. The liability and related compensation expense of these awards for each period ~~for these awards~~ is recognized by dividing the fair value of the total liability by the requisite service period and recording the pro rata share for the period for which service has already been provided. As there are inherent uncertainties related to these factors and the Company’s judgment in applying them to the fair value determinations, there is risk that the recorded performance unit compensation may not accurately reflect the amount ultimately earned by the members of management.

The 44,481 outstanding 2013 ~~performance unit awards~~Performance Unit Awards have a performance period of January 1, 2013 to December 31, 2015 and are expected to be paid in the first quarter of 2016 if the performance criteria are met. The 27,381 outstanding 2012 performance units have a performance period of January 1, 2012 to December 31, 2014 and are expected to be paid in the first quarter of 2015 if the performance criteria are met.

Compensation expense for these awards amounted to ~~$0.1~~$1.1 million ~~for~~and $2.1 million in the three months ended ~~March 31,~~June 30, 2014 and 2013, respectively, and $1.2 million and $2.2 million in the six months ended June 30, 2014 and 2013, respectively, and is recognized in "General and administrative" in the Company’s unaudited consolidated statements of operations, and the corresponding liabilities are included in "Other current liabilities" and "Other noncurrent liabilities" in the unaudited consolidated balance sheets.

F—Income taxes

Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets

~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

and liabilities and their respective tax bases and operating losses and tax credit carry-forwards. Under this method, deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income (loss) in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is determined it is more likely than not that the related tax benefit will not be realized. On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances, if necessary.

The Company evaluates uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, the Company determines whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more-likely-than-not threshold is measured to determine the amount of benefit to be recognized in the consolidated financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50% likely of being realized upon settlement. The Company has

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

no unrecognized tax benefits related to uncertain tax positions in the consolidated financial statements at ~~March 31,~~June 30, 2014 or December 31, 2013.

The Company is subject to corporate income taxes and the Texas franchise tax. Income tax ~~expense~~(expense) benefit attributable to income (loss) from continuing operations for the periods presented consisted of the following:


	Three months ended March 31,						Three months ended June 30,					Six months ended June 30,
(in thousands)	2014			2013			2014		2013			2014		2013
Current taxes	$	—		$	—		$	—	$	—		$	—	$	—
Deferred taxes	(107		)	(1,110		)	10,374		(20,047		)	10,267		(21,157		)
Income tax expense	$	(107	)	$	(1,110	)
Income tax benefit (expense)							$	10,374	$	(20,047	)	$	10,267	$	(21,157	)

The following presents the comprehensive provision for income taxes for the periods presented:


	Three months ended March 31,						Three months ended June 30,					Six months ended June 30,
(in thousands)	2014			2013			2014		2013			2014		2013
Comprehensive provision for income taxes allocable to:
Continuing operations	$	(107	)	$	(1,110	)	$	10,374	$	(20,047	)	$	10,267	$	(21,157	)
Discontinued operations	—			(153		)	—		(291		)	—		(444		)
Comprehensive provision for income taxes	$	(107	)	$	(1,263	)	$	10,374	$	(20,338	)	$	10,267	$	(21,601	)

Income tax ~~expense~~benefit (expense) attributable to income (loss) from continuing operations before income taxes differed from amounts computed by applying the applicable federal income tax rate of 35% to pre-tax earnings as a result of the following:


	Three months ended March 31,						Three months ended June 30,						Six months ended June 30,
(in thousands)	2014			2013			2014			2013			2014			2013
Income tax benefit (expense) computed by applying the statutory rate	$	37		$	(764	)	$	10,246		$	(18,816	)	$	10,283		$	(19,580	)
State income tax, net of federal tax benefit and increase in valuation allowance	1,287			(21		)	347			(551		)	1,634			(572		)
Non-deductible stock-based compensation	(116		)	(175		)	(123		)	(164		)	(239		)	(339		)
Stock-based compensation tax deficiency	(141		)	(291		)	(15		)	(120		)	(156		)	(411		)
Change in deferred tax valuation allowance	(1,078		)	(9		)	(34		)	(20		)	(1,112		)	(29		)
Other items	(96		)	150			(47		)	(376		)	(143		)	(226		)
Income tax expense	$	(107	)	$	(1,110	)
Income tax benefit (expense)							$	10,374		$	(20,047	)	$	10,267		$	(21,157	)

~~For the three months ended March 31, 2014 and 2013, the~~The effective rate on income (loss) from continuing operations before income taxes was ~~not meaningful due to~~35% and 36% for the ~~significant effect of discrete items on a relatively small loss from continuing operations.~~three months ended June 30, 2014 and 2013, respectively, and 35% and 37% for the six months ended June 30, 2014 and 2013, respectively. The Company's effective tax rate is affected by recurring permanent differences and by discrete items that may occur in any given year, but are not consistent from year to year.

The impact of significant discrete items is separately recognized in the quarter in which they occur. During the three and six months ended ~~March 31,~~June 30, 2014 and 2013, certain shares related to restricted stock awards vested at times when the Company's stock price was lower than the fair value of those shares at the time of grant. As a result, the income tax deduction related to such shares is less than the expense previously recognized for book purposes. During the three and six months ended ~~March 31,~~June 30, 2014,

~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

certain restricted stock options were exercised. The income tax deduction related to the options intrinsic value was less than the expense previously recognized for book purposes. In accordance with GAAP, such shortfalls reduce additional paid-in capital to the extent windfall tax benefits have been previously recognized. However, the Company has not previously recognized any windfall tax benefits. Therefore, the tax impact of these shortfalls totaling $0.1 million and ~~$0.3~~$0.2 million for the three and six months ended ~~March 31,~~June 30, 2014, respectively, and $0.1 million and $0.4 million for the three and six months ended June 30, 2013, respectively, is included in income tax expense attributable to continuing operations for the period.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Significant components of the Company’s deferred tax liabilities for the periods presented are as follows:


(in thousands)	March 31, 2014			December 31, 2013			June 30, 2014			December 31, 2013
Net operating loss carry-forward	$	287,796		$	284,890		$	310,579		$	284,890
Oil and natural gas properties and equipment	(314,097		)	(278,735		)	(351,515		)	(278,735		)
Derivatives	8,819			(30,859		)	30,969			(30,859		)
Stock-based compensation	5,583			6,578			7,807			6,578
Accrued bonus	188			3,740			2,368			3,740
Capitalized interest	2,271			2,099			2,411			2,099
Other	(2,089		)	(240		)	(3,739		)	(240		)
Gross deferred tax liability	(11,529		)	(12,527		)	(1,120		)	(12,527		)
Valuation allowance	(1,237		)	(132		)	(1,272		)	(132		)
Net deferred tax liability	$	(12,766	)	$	(12,659	)	$	(2,392	)	$	(12,659	)

Net deferred tax assets and liabilities were classified in the unaudited consolidated balance sheets as follows for the periods presented:


(in thousands)	March 31, 2014			December 31, 2013			June 30, 2014			December 31, 2013
Deferred tax asset	$	1,075		$	3,634		$	13,588		$	3,634
Deferred tax liability	(13,841		)	(16,293		)	(15,980		)	(16,293		)
Net deferred tax liability	$	(12,766	)	$	(12,659	)	$	(2,392	)	$	(12,659	)

The Company had federal net operating loss carry-forwards totaling $~~813.7~~879.0 million and state of Oklahoma net operating loss carry-forwards totaling $~~106.7~~112.8 million as of ~~March 31,~~June 30, 2014. These carry-forwards begin expiring in 2026. As of ~~March 31,~~June 30, 2014, the Company believes the federal and the state of Oklahoma net operating loss carry-forwards are 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 on either the federal or the Oklahoma net operating loss carry-forwards. Such consideration included estimated future projected earnings based on existing reserves and projected future cash flows from its oil and natural gas reserves (including the timing of those cash flows), the reversal of deferred tax liabilities recorded as of ~~March 31,~~June 30, 2014, 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.

The Company's federal and state operating loss carry-forwards include windfall tax deductions from vestings of certain restricted stock awards and stock option exercises that were not recorded in the Company's income tax provision. The amount of windfall tax benefit recognized in additional paid-in capital is limited to the amount of benefit realized currently in income taxes payable. As of ~~March 31,~~June 30, 2014, the Company had suspended additional paid-in capital credits of ~~$3.2~~$4.2 million related to windfall tax deductions. Upon realization of the net operating loss carry-forwards from such windfall tax deductions, the Company would record a benefit of up to ~~$3.2~~$4.2 million in additional paid-in capital.

The Company maintains a valuation allowance to reduce certain deferred tax assets to amounts that are more likely than not to be realized. As of ~~March 31,~~June 30, 2014, a full valuation allowance of $~~1.2~~1.3 million was recorded against the deferred tax asset related to the Company’s charitable contribution carry-forward of $~~3.5~~3.6 million.

The Company's income tax returns for the years 2010 through 2013 remain open and subject to examination by federal tax authorities and/or the tax authorities in Oklahoma, Texas and Louisiana which are the jurisdictions where the Company has or had operations. Additionally, the statute of limitations for examination of federal net operating loss carry-forwards typically does not begin to run until the year the attribute is utilized in a tax return. The Company's 2011 federal income tax return is currently under examination.

~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

G—Derivatives

1. Commodity derivatives

The Company engages in derivative transactions such as collars, swaps, puts and basis swaps to hedge price risks due to unfavorable changes in oil and natural gas prices related to its oil and natural gas production. As of ~~March 31,~~June 30, 2014, the Company had 3748 open derivative contracts with financial institutions which extend from ~~April~~July 2014 to December 2016. None of these contracts were designated as hedges for accounting purposes. The contracts are recorded at fair value on the balance sheet

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

and gains and losses are recognized in current period earnings. Gains and losses on derivatives are reported on the unaudited consolidated statements of operations in the respective ~~"Loss~~"Gain (loss) on derivatives" amounts.

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

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

The oil basis swap transaction has an established fixed basis differential. The Company's oil basis swap differential is between the West Texas Intermediate Midland Argus ("Midland Argus") index crude oil price and the West Texas Intermediate Argus Cushing ("WTI Argus") index crude oil price. When the WTI Argus price less the fixed basis differential is greater than the actual Midland Argus price, the difference multiplied by the hedged contract volume is paid to the Company by the counterparty. When the WTI Argus price less the fixed basis differential is less than the actual Midland Argus price, the difference multiplied by the hedged contract volume is paid by the Company to the counterparty.

During the ~~three months ended March 31, 2014, the Company entered into additional commodity contracts to hedge a portion~~first quarter of ~~its estimated future production. The following table summarizes information about these additional commodity derivative contracts:~~

Aggregate
volumes

Swap
price
Contract period
Natural gas (volumes in MMBtu):
Swap⁽¹⁾
3,060,000
$ 4.32
March 2014 - December 2014
Swap⁽¹⁾
2,448,000
$ 4.32
March 2014 - December 2014

~~(1)These natural gas derivatives are settled based on the Inside FERC West Texas Waha index price for the calculation period.~~

~~During the three months ended March 31,~~ 2014, the Company unwound a physical commodity contract and the associated oil basis swap financial derivative contract which hedged the differential between the Light Louisiana Sweet Argus and the Brent International Petroleum Exchange index oil prices. Prior to its unwind, the physical commodity contract qualified to be scoped out of mark-to-market accounting in accordance with the normal purchase and normal sale scope exemption. Once modified to settle financially in the unwind agreement, the contract ceased to qualify for the normal purchase and normal sale scope exemption, therefore requiring it to be marked-to-market. The Company received net proceeds of ~~$76.7~~$76.7 million from the early termination of these contracts. The Company agreed to settle the contracts early due to the counterparty's decision to exit the physical commodity trading business.

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

During the six months ended June 30, 2014, the Company entered into additional commodity contracts to hedge a portion of its estimated future production. The following table summarizes information about these additional commodity derivative contracts:



	Aggregate volumes	Swap price		Floor price		Ceiling price		Contract period
Oil (volumes in Bbl):
Swap	288,000	$	103.56	$	—	$	—	July 2014 - December 2014
Swap	672,000	$	96.56	$	—	$	—	January 2015 - December 2015
Price collar	696,000	$	—	$	80.00	$	100.20	January 2016 - December 2016
Swap	640,500	$	84.85	$	—	$	—	January 2016 - December 2016
Swap	933,300	$	84.80	$	—	$	—	January 2016 - December 2016
Natural gas (volumes in MMBtu):
Swap⁽¹⁾	5,508,000	$	4.32	$	—	$	—	March 2014 - December 2014
Price collar⁽¹⁾	3,797,500	$	—	$	4.00	$	5.50	May 2014 - December 2014
Price collar⁽¹⁾	20,440,000	$	—	$	3.00	$	5.95	January 2015 - December 2015
Price collar⁽¹⁾	18,666,000	$	—	$	3.00	$	5.60	January 2016 - December 2016

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

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

The following table summarizes open positions as of ~~March 31,~~June 30, 2014, and represents, as of such date, derivatives in place through December 2016, on annual production volumes:


	Remaining Year 2014			Year 2015		Year 2016		Remaining Year 2014			Year 2015		Year 2016
Oil positions:
Puts:
Hedged volume (Bbl)	405,000			456,000		—		270,000			456,000		—
Weighted-average price ($/Bbl)	$	75.00		$	75.00	$	—	$	75.00		$	75.00	$	—
Swaps:
Hedged volume (Bbl)	1,622,497			—		—		1,371,998			672,000		1,573,800
Weighted-average price ($/Bbl)	$	94.44		$	—	$	—	$	96.35		$	96.56	$	84.82
Collars:
Hedged volume (Bbl)	2,209,500			6,557,020		1,860,000		1,473,000			6,557,020		2,556,000
Weighted-average floor price ($/Bbl)	$	86.42		$	79.81	$	80.00	$	86.42		$	79.81	$	80.00
Weighted-average ceiling price ($/Bbl)	$	104.89		$	95.40	$	91.37	$	104.89		$	95.40	$	93.77
Basis swaps:
Hedged volume⁽¹⁾ (Bbl)	1,650,000			—		—		1,104,000			—		—
Weighted-average price(1) ($/Bbl)	$	(1.00	)	$	—	$	—
Weighted-average price⁽¹⁾ ($/Bbl)								$	(1.00	)	$	—	$	—
Natural gas positions:
Swaps:
Hedged volume (MMBtu)	4,950,000			—		—		3,312,000			—		—
Weighted-average price ($/MMBtu)	$	4.32		$	—	$	—	$	4.32		$	—	$	—
Collars:
Hedged volume (MMBtu)	7,200,000			8,160,000		—		7,652,000			28,600,000		18,666,000
Weighted-average floor price ($/MMBtu)	$	3.00		$	3.00	$	—	$	3.37		$	3.00	$	3.00
Weighted-average ceiling price ($/MMBtu)	$	5.50		$	6.00	$	—	$	5.50		$	5.96	$	5.60


(1)	The associated oil basis swap derivative is settled based on the differential between the WTI Argus index oil price and the Midland Argus oil futures.

The following represents cash settlements (paid) received for matured derivatives for the periods presented:


	Three months ended March 31,						Three months ended June 30,						Six months ended June 30,
(in thousands)	2014			2013			2014			2013			2014			2013
Commodity derivatives (paid) received	$	(1,431	)	$	3,777		$	(4,420	)	$	1,086		$	(5,851	)	$	4,863
Interest rate derivatives paid	—			(101		)	—			(105		)	—			(206		)
Cash settlements (paid) received for matured derivatives, net	$	(1,431	)	$	3,676		$	(4,420	)	$	981		$	(5,851	)	$	4,657

2. Interest rate derivatives

The Company is exposed to market risk for changes in interest rates related to any drawn amount on its Senior Secured Credit Facility. In prior periods, interest rate derivative agreements were used to manage a portion of the exposure related to changing interest rates by converting floating-rate debt to fixed-rate debt. If the London Interbank Offered Rate ("LIBOR") was lower than the fixed rate in the contract, the Company was required to pay the counterparties the difference, and conversely, the counterparties were required to pay the Company if LIBOR was higher than the fixed rate in the contract. The Company did not designate the interest rate derivatives as cash flow hedges; therefore, the changes in fair value of these instruments were recorded in current earnings. The Company had one interest rate swap and one interest rate cap outstanding for a notional amount of $100.0 million with fixed pay rates of 1.11% and 3.00%, respectively, until their expiration in September 2013. No interest rate derivatives were in place ~~as of March 31,~~during the period ended June 30, 2014.

1920

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

3. Balance sheet presentation

The Company’s oil and natural gas commodity ~~derivatives and interest rate~~ derivatives are presented on a net basis in "Derivatives" on the unaudited consolidated balance sheets.

The following summarizes the fair value of derivatives outstanding on a gross basis as ~~of:~~of June 30, 2014 and December 31, 2013, respectively:


(in thousands)	March 31, 2014			December 31, 2013		June 30, 2014			December 31, 2013
Assets:
Commodity derivatives:
Oil derivatives	$	38,699		$	140,496	$	20,484		$	140,496
Natural gas derivatives	479			657		2,125			657
Total assets	$	39,178		$	141,153	$	22,609		$	141,153

Liabilities:
Commodity derivatives:
Oil derivatives⁽¹⁾	$	58,984		$	56,818	$	96,749		$	56,818
Natural gas derivatives⁽²⁾	2,584			2,278		5,191			2,278
Total liabilities	$	61,568		$	59,096	$	101,940		$	59,096

Net derivative position	$	(22,390	)	$	82,057	$	(79,331	)	$	82,057


(1)	The oil derivatives fair value includes a deferred premium liability of $~~9.4~~7.9 million and $11.1 million as of ~~March 31,~~June 30, 2014 and December 31, 2013, respectively.


(2)	The natural gas derivatives fair value includes a deferred premium liability of $~~1.4~~1.1 million and $1.6 million as of ~~March 31,~~June 30, 2014 and December 31, 2013, respectively.

By using derivatives to hedge exposures to changes in commodity prices and interest rates, the Company exposes itself to credit risk and market risk. Market risk is the exposure to changes in the market price of oil and natural gas, which are subject to fluctuations from a variety of factors, including changes in supply and demand. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, thereby creating credit risk. The Company’s counterparties are participants in the Senior Secured Credit Facility which is secured by the Company’s oil and natural gas reserves; therefore, the Company is not required to post any collateral. The Company does not require collateral from its 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 are also lenders in the Senior Secured Credit Facility and 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. In accordance with the Company’s standard practice, its commodity and interest rate derivatives are subject to counterparty netting under agreements governing such derivatives and, therefore, the risk of such loss is somewhat mitigated as of ~~March 31,~~June 30, 2014.

H—Fair value measurements

The Company accounts for its oil and natural gas commodity derivatives and, in prior periods, its interest rate 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).

2021

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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



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

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

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

When the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety. The Company conducts a review of fair value hierarchy classifications on an annual basis. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities. Transfers between fair value hierarchy levels are recognized and reported in the period in which the transfer occurred. No transfers between fair value hierarchy levels occurred during the ~~three~~six months ended ~~March 31,~~June 30, 2014 or 2013.

1. Fair value measurement on a recurring basis

The following presents the Company’s fair value hierarchy for assets and liabilities measured at fair value on a recurring basis for the periods presented:


(in thousands)	Level 1		Level 2			Level 3			Total fair value			Level 1		Level 2			Level 3			Total fair value
As of March 31, 2014:
As of June 30, 2014:
Commodity derivatives	$	—	$	(11,600	)	$	—		$	(11,600	)	$	—	$	(70,306	)	$	—		$	(70,306	)
Deferred premiums	—		—			(10,790		)	(10,790		)	—		—			(9,025		)	(9,025		)
Total	$	—	$	(11,600	)	$	(10,790	)	$	(22,390	)	$	—	$	(70,306	)	$	(9,025	)	$	(79,331	)



(in thousands)	Level 1		Level 2		Level 3			Total fair value
As of December 31, 2013:
Commodity derivatives	$	—	$	94,741	$	—		$	94,741
Deferred premiums	—		—		(12,684		)	(12,684		)
Total	$	—	$	94,741	$	(12,684	)	$	82,057

These items are included in "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 commodity derivatives include the NYMEX natural gas and oil prices, appropriate ~~risk adjusted~~risk-adjusted discount rates and other relevant data. Significant Level 2 assumptions associated with the calculation of discounted cash flows used in the mark-to-market analysis of interest rate swaps ~~include~~included the interest rate curves, appropriate risk adjusted discount rates and other relevant data.

The Company’s deferred premiums associated with its commodity 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 commodity 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 2.00% 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

2122

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

significantly lower (higher) fair value measurement for each new contract entered into which contained a deferred premium; however, the valuation for the deferred premiums already recorded would remain unaffected. While the Company believes the sources utilized to arrive at the fair value estimates are reliable, different sources or methods could have yielded different fair value estimates; therefore, on a quarterly basis, the valuation is compared to counterparty valuations and a third-party valuation of the deferred premiums for reasonableness.

The following table presents actual cash payments required for deferred premium contracts in place as of ~~March 31,~~June 30, 2014, and for the calendar years following:


(in thousands)
Remaining 2014	$	5,460	$	3,640
2015	5,166		5,166
2016	358		358
Total	$	10,984	$	9,164

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


	Three months ended March 31,						Three months ended June 30,						Six months ended June 30,
(in thousands)	2014			2013			2014			2013			2014			2013
Balance of Level 3 at beginning of period	$	(12,684	)	$	(24,709	)	$	(10,790	)	$	(22,438	)	$	(12,684	)	$	(24,709	)
Change in net present value of deferred premiums for derivatives	(65		)	(151		)	(55		)	(131		)	(120		)	(282		)
Settlements	1,959			2,422			1,820			2,827			3,779			5,249
Balance of Level 3 at end of period	$	(10,790	)	$	(22,438	)	$	(9,025	)	$	(19,742	)	$	(9,025	)	$	(19,742	)

2. 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~~cash-flow models. No impairments of long-lived assets were recorded in the ~~three~~six months ended ~~March 31,~~June 30, 2014 or 2013.

The accounting policies for impairment of oil and natural gas properties are discussed in the audited consolidated financial statements and notes thereto included in the 2013 Annual Report. Significant inputs included in the calculation of discounted cash flows used in the impairment analysis include the Company’s estimate of operating and development costs, anticipated production of proved reserves and other relevant data.

I—Credit risk

The Company’s oil and natural gas sales are 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 properties operated by the Company. Management believes that any credit risk imposed by a concentration in the oil and natural gas industry is offset by the creditworthiness of the Company’s customer base and industry partners. The Company routinely assesses the recoverability of all material trade and other receivables to determine collectability.

The Company uses derivatives to hedge its exposure to oil and natural gas price volatility and, in the past, its exposure to interest rate risk associated with the Senior Secured Credit Facility. 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 Note G for additional information regarding the Company’s derivatives.

~~Laredo Petroleum, Inc.~~

~~Condensed notes to the consolidated financial statements~~

~~(Unaudited)~~

J—Commitments and contingencies

1. Litigation

~~The~~From time to time the Company ~~may be~~is involved in legal proceedings and/or may be subject to industry rulings that could bring rise to claims in the ordinary course of business. The Company has concluded that the likelihood is remote that the

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

ultimate resolution of any pending litigation or pending claims will be material or have a material adverse effect on the Company’s business, financial position, results of operations or liquidity.

2. Drilling contracts

The Company has committed to several short-term drilling contracts with various third parties in order to complete its various drilling projects. The contracts contain an early termination clause that requires the Company to pay significant penalties to the third party should the Company cease drilling efforts. These penalties would negatively impact the Company’s financial statements upon contract termination. Future commitments ~~are $31.1~~of $34.8 million as of ~~March 31,~~June 30, 2014 ~~and~~ are not recorded in the accompanying unaudited consolidated balance sheets. Management does not anticipate canceling any drilling contracts or discontinuing drilling efforts in 2014.

3. 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. Because these rules and regulations are frequently amended or reinterpreted, the Company is unable to predict the future cost or impact of complying with these regulations.

K—Net income (loss) per share

Basic net income (loss) per share is computed by dividing net income (loss) by the weighted-average number of shares outstanding for the period. Diluted net income (loss) per share reflects the potential dilution of non-vested restricted stock awards, ~~2014 performance share awards~~Performance Share Awards and outstanding restricted stock options. For the three and six months ended ~~March 31,~~June 30, 2014, all of these potentially dilutive items were anti-dilutive due to the Company's net loss and, therefore, were excluded from the calculation of diluted net loss per share.

The effect of the Company's outstanding options that were granted in February 2012 to purchase ~~431,086~~414,239 shares of common stock at $24.11 per share were excluded from the calculation of diluted net income per share for the three and six months ended ~~March 31,~~June 30, 2013 because the exercise price of those options was greater than the average market price during the period, and, therefore, the inclusion of these outstanding options would have been anti-dilutive. The effect of the Company's outstanding options that were granted in February 2013 to purchase ~~989,456~~968,938 shares of common stock at $17.34 per share were excluded from the calculation of diluted net income per share for the three and six months ended ~~March 31,~~June 30, 2013, because, utilizing the treasury method, the sum of the assumed proceeds ~~exceeds~~including the unrecognized compensation, exceeded the average stock price during the period and, therefore, the inclusion of these outstanding options would have been anti-dilutive.

2324

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

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


	Three months ended March 31,					Three months ended June 30,					Six months ended June 30,
(in thousands, except for per share data)	2014			2013		2014			2013		2014			2013
Net income (loss) (numerator):
Income (loss) from continuing operations—basic and diluted	$	(213	)	$	1,137	$	(18,899	)	$	35,294	$	(19,112	)	$	36,431
Income from discontinued operations, net of tax—basic and diluted	—			272		—			518		—			790
Net income (loss)—basic and diluted	$	(213	)	$	1,409	$	(18,899	)	$	35,812	$	(19,112	)	$	37,221
Weighted-average shares (denominator):
Weighted-average shares—basic	141,067			127,200		141,298			127,362		141,183			127,281
Non-vested restricted stock	—			1,651		—			2,022		—			1,838
Weighted-average shares—diluted	141,067			128,851		141,298			129,384		141,183			129,119
Net income (loss) per share:
Basic:
Income (loss) from continuing operations	$	—		$	0.01	$	(0.13	)	$	0.28	$	(0.14	)	$	0.29
Income from discontinued operations, net of tax	—			—		—			—		—			0.01
Net income (loss) per share	$	—		$	0.01	$	(0.13	)	$	0.28	$	(0.14	)	$	0.30

Diluted:
Income (loss) from continuing operations	$	—		$	0.01	$	(0.13	)	$	0.27	$	(0.14	)	$	0.28
Income from discontinued operations, net of tax	—			—		—			—		—			0.01
Net income (loss) per share	$	—		$	0.01	$	(0.13	)	$	0.27	$	(0.14	)	$	0.29

L—Variable interest entity

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

~~During the three months ended March 31, 2014 and 2013,~~ Laredo Midstream contributed $~~11.3~~8.2 million and $~~0.9~~19.5 million, during the three and six months ended June 30, 2014, respectively, and $2.3 million and $3.2 million during the three and six months ended June 30, 2013, respectively, to Medallion Gathering & Processing, LLC ("Medallion"), a Texas limited liability company. Laredo Midstream holds 49% of Medallion ownership units. Medallion, which was formed on October 31, 2012 and its wholly owned subsidiary, Medallion Pipeline Company, LLC ("MPC"), a Texas limited liability company formed on September 9, 2013, were established for the purpose of developing midstream solutions and providing midstream infrastructure to bring discovered oil and natural gas to market. Laredo Midstream and the other 51% interest-holder have agreed that the voting rights of Medallion, the profit and loss sharing, and the additional capital contribution requirements shall be equal to the ownership unit percentage held. Additionally, Medallion requires a super-majority vote of 75% for all key operating and business decisions. The Company has determined that Medallion is a VIE. However, Laredo Midstream is not considered to be the primary beneficiary of the VIE because Laredo Midstream does not have the power to direct the activities that most significantly affect Medallion's economic performance. As such, Medallion is accounted for under the equity method of accounting with the Company's proportionate share of Medallion's net ~~loss~~income (loss) reflected in the unaudited consolidated statements of operations as ~~"Income (loss)~~"Loss from equity method investee" and the carrying amount reflected on the unaudited consolidated balance sheets as "Investment in equity method investee."

As of ~~March 31,~~June 30, 2014, Laredo Midstream has a remaining commitment to contribute an additional ~~$14.4~~$21.6 million to Medallion in 2014 towards the construction of a pipeline by MPC. The Company has recorded a capital contribution payable of ~~$8.2~~$18.1 million related to the ~~first~~capital call for the second and third quarter cash requirements of the project and a payable of ~~$1.4 million related to its minimum~~$2.0

2425

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

million related to its minimum volume commitment to Medallion, which is reported on the unaudited consolidated balance sheet as "Accrued payable - affiliates." The corresponding expense is reported on the unaudited consolidated statements of operations in the ~~"Transportation and treating~~"Natural gas volume commitment - affiliates" line item.

M—Recent accounting pronouncements

In ~~July 2013,~~May 2014, the Financial Accounting Standards Board ("FASB") issued a comprehensive new revenue recognition standard that supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities—Oil and Gas—Revenue Recognition. The core principle of the new guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for transferring those goods or services. The new standard also requires significantly expanded disclosure regarding the qualitative and quantitative information of an entity's nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The standard creates a five-step model that requires companies to exercise judgment when considering the terms of a contract and all relevant facts and circumstances. The standard allows for several transition methods: (a) a full retrospective adoption in which the standard is applied to all of the periods presented, or (b) a modified retrospective adoption in which the standard is applied only to the most current period presented in the financial statements, including additional disclosures of the standard’s application impact to individual financial statement line items. This standard is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. The Company is currently evaluating this standard and its existing revenue recognition policies to determine which contracts in the scope of the guidance will be affected by the new requirements and what impact they will have on its consolidated financial statements upon adoption of this standard.

In April 2014, the FASB issued guidance on reporting discontinued operations and disclosures of disposals of components of an entity. The guidance changes the criteria for reporting discontinued operations, including raising the threshold for a disposal to qualify as discontinued operations. The guidance also requires entities to provide additional disclosure about discontinued operations as well as disposal transactions that do not meet the discontinued operations criteria. The pronouncement is effective for annual and interim periods beginning after December 15, 2014. Early adoption is permitted for disposals or for assets classified as held for sale that have not been reported in previously issued financial statements. The Company elected to early adopt this guidance in the second quarter of 2014 on a prospective basis, and the adoption did not have an effect on its consolidated financial statements.

In July 2013, the FASB issued guidance on the presentation of an unrecognized tax benefit when a net operating loss carry-forward, a similar tax loss or a tax credit carry-forward exists. The guidance requires an unrecognized tax benefit, or a portion of an unrecognized tax benefit, to be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carry-forward, a similar tax loss or a tax credit carry-forward except when (i) a net operating loss carry-forward, a similar tax loss or a tax credit carry-forward is not available at the reporting date under the tax law of the applicable jurisdiction to settle any additional income taxes that would result from the disallowance of a tax position, or (ii) the tax law of the applicable jurisdiction does not require the entity to use, and the entity does not intend to use, the deferred tax asset for such purpose. In those situations the unrecognized tax benefit should be presented in the financial statements as a liability and should not be combined with deferred tax assets. The Company adopted this guidance on January 1, 2014, and the adoption ~~of this guidance~~ did not have an effect on its consolidated financial statements.

N—Subsidiary guarantees

Laredo Midstream has fully and unconditionally guaranteed the 2019 Notes, the January 2022 Notes, the May 2022 Notes and the Senior Secured Credit Facility. In accordance with practices accepted by the SEC, Laredo has prepared condensed consolidating financial statements in order to quantify the assets, results of operations and cash flows of Laredo Midstream as a subsidiary guarantor. The following unaudited condensed consolidating balance sheets as of ~~March 31,~~June 30, 2014 and December 31, 2013, ~~and~~ unaudited condensed consolidating statements of operations for the three and six months ended June 30, 2014 and 2013 and unaudited condensed consolidating statements of cash flows for the ~~three~~six months ended ~~March 31,~~June 30, 2014 and 2013, present financial information for Laredo on a stand-alone basis (carrying any investment in subsidiaries under the equity method), financial information for Laredo Midstream 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 Laredo Midstream are recorded on Laredo's statements of financial position, statements of operations and statements of cash flows as it is a disregarded entity for income tax purposes. Laredo and Laredo Midstream are not restricted from making distributions to each other.

~~Condensed consolidating balance sheet~~

~~March 31,~~ During the three months ended June 30, 2014,

~~(Unaudited)~~

(in thousands) Laredo Laredo Midstream
Intercompany
eliminations

Consolidated
company
Accounts receivable $ 85,030
$ 37
$ (4,130 ) $ 80,937
Other current assets 569,854
—
—
569,854
Total oil and natural gas properties, net 2,291,481
—
—
2,291,481
Total pipeline and gathering assets, net —
54,383
—
54,383
Total other fixed assets, net 28,914
—
—
28,914
Investment in subsidiaries and equity method investee 57,036
22,803
(57,036 ) 22,803
Total other long-term assets 33,210
—
—
33,210
Total assets $ 3,065,525
$ 77,223
$ (61,166 ) $ 3,081,582
Accounts payable $ 8,001
$ 4,130
$ (4,130 ) $ 8,001
Other current liabilities 235,484
16,057
—
251,541
Other long-term liabilities 44,960
—
—
44,960
Long-term debt 1,501,479
—
—
1,501,479
Stockholders’ equity 1,275,601
57,036
(57,036 ) 1,275,601
Total liabilities and stockholders’ equity $ 3,065,525
$ 77,223
$ (61,166 ) $ 3,081,582

certain midstream service assets were transferred from Laredo to Laredo Midstream at historical cost.

2526

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Condensed consolidating balance sheet

~~December 31, 2013~~June 30, 2014

(Unaudited)


(in thousands)	Laredo		Laredo Midstream		Intercompany eliminations			Consolidated company		Laredo		Laredo Midstream		Intercompany eliminations			Consolidated company
Accounts receivable	$	77,318	$	—	$	—		$	77,318
Accounts receivable, net										$	95,604	$	116	$	—		$	95,720
Other current assets	230,291		—		—			230,291		434,888		13		—			434,901
Total oil and natural gas properties, net	2,135,348		—		—			2,135,348		2,475,094		—		—			2,475,094
Total pipeline and gathering assets, net	—		41,498		—			41,498
Total midstream service assets, net										—		74,258		—			74,258
Total other fixed assets, net	27,478		—		—			27,478		28,574		290		—			28,864
Investment in subsidiaries and equity method investee	36,666		5,913		(36,666		)	5,913		88,330		40,871		(88,330		)	40,871
Total other long-term assets	105,914		—		—			105,914		31,330		—		—			31,330
Total assets	$	2,613,015	$	47,411	$	(36,666	)	$	2,623,760	$	3,153,820	$	115,548	$	(88,330	)	$	3,181,038

Accounts payable	$	12,216	$	3,786	$	—		$	16,002	$	18,017	$	370	$	—		$	18,387
Other current liabilities	231,008		6,959		—			237,967		289,433		26,848		—			316,281
Other long-term liabilities	45,997		—		—			45,997		80,642		—		—			80,642
Long-term debt	1,051,538		—		—			1,051,538		1,501,419		—		—			1,501,419
Stockholders’ equity	1,272,256		36,666		(36,666		)	1,272,256		1,264,309		88,330		(88,330		)	1,264,309
Total liabilities and stockholders’ equity	$	2,613,015	$	47,411	$	(36,666	)	$	2,623,760	$	3,153,820	$	115,548	$	(88,330	)	$	3,181,038

Condensed consolidating ~~statement of operations~~balance sheet

~~For the three months ended March~~December 31, ~~2014~~2013

(Unaudited)

(in thousands) Laredo Laredo Midstream
Intercompany
eliminations

Consolidated
company
Total operating revenues $ 173,214
$ 1,030
$ (934 ) $ 173,310
Total operating costs and expenses 112,510
1,696
(934 ) 113,272
Income (loss) from operations 60,704
(666 ) —
60,038
Interest expense, net (28,903 ) —
—
(28,903 )
Other, net (31,907 ) (33 ) 699
(31,241 )
Loss from continuing operations before income tax (106 ) (699 ) 699
(106 )
Income tax expense (107 ) —
—
(107 )
Loss from continuing operations (213 ) (699 ) 699
(213 )
Net loss $ (213 ) $ (699 ) $ 699
$ (213 )



(in thousands)	Laredo		Laredo Midstream		Intercompany eliminations			Consolidated company
Accounts receivable, net	$	77,318	$	—	$	—		$	77,318
Other current assets	230,291		—		—			230,291
Total oil and natural gas properties, net	2,135,348		—		—			2,135,348
Total midstream service assets, net	5,802		41,498		—			47,300
Total other fixed assets, net	21,676		—		—			21,676
Investment in subsidiaries and equity method investee	36,666		5,913		(36,666		)	5,913
Total other long-term assets	105,914		—		—			105,914
Total assets	$	2,613,015	$	47,411	$	(36,666	)	$	2,623,760

Accounts payable	$	12,216	$	3,786	$	—		$	16,002
Other current liabilities	231,008		6,959		—			237,967
Other long-term liabilities	45,997		—		—			45,997
Long-term debt	1,051,538		—		—			1,051,538
Stockholders’ equity	1,272,256		36,666		(36,666		)	1,272,256
Total liabilities and stockholders’ equity	$	2,613,015	$	47,411	$	(36,666	)	$	2,623,760

2627

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Condensed consolidating statement of operations

For the three months ended ~~March 31, 2013~~June 30, 2014

(Unaudited)

(in thousands) Laredo Laredo Midstream
Intercompany
eliminations

Consolidated
company
Total operating revenues $ 163,669
$ 2,646
$ (2,610 ) $ 163,705
Total operating costs and expenses 120,831
979
(2,610 ) 119,200
Income from operations 42,838
1,667
—
44,505
Interest expense, net (25,334 ) —
—
(25,334 )
Other, net (13,960 ) (64 ) (2,900 ) (16,924 )
Income from continuing operations before income tax 3,544
1,603
(2,900 ) 2,247
Income tax expense (1,110 ) —
—
(1,110 )
Income from continuing operations 2,434
1,603
(2,900 ) 1,137
Income (loss) from discontinued operations, net of tax (1,025 ) 1,297
—
272
Net income $ 1,409
$ 2,900
$ (2,900 ) $ 1,409



(in thousands)	Laredo			Laredo Midstream			Intercompany eliminations			Consolidated company
Total operating revenues	$	182,872		$	1,542		$	(1,370	)	$	183,044
Total operating costs and expenses	116,596			3,257			(1,370		)	118,483
Income (loss) from operations	66,276			(1,715		)	—			64,561
Interest expense, net	(30,463		)	—			—			(30,463		)
Other, net	(65,086		)	(44		)	1,759			(63,371		)
Loss from continuing operations before income tax	(29,273		)	(1,759		)	1,759			(29,273		)
Deferred income tax benefit	10,374			—			—			10,374
Loss from continuing operations	(18,899		)	(1,759		)	1,759			(18,899		)
Net loss	$	(18,899	)	$	(1,759	)	$	1,759		$	(18,899	)

Condensed consolidating statement of operations

For the three months ended June 30, 2013

(Unaudited)



(in thousands)	Laredo			Laredo Midstream			Intercompany eliminations			Consolidated company
Total operating revenues	$	177,296		$	2,718		$	(2,718	)	$	177,296
Total operating costs and expenses	122,028			572			(2,718		)	119,882
Income from operations	55,268			2,146			—			57,414
Interest expense, net	(25,931		)	—			—			(25,931		)
Other, net	27,049			(49		)	(3,142		)	23,858
Income from continuing operations before income tax	56,386			2,097			(3,142		)	55,341
Deferred income tax expense	(20,047		)	—			—			(20,047		)
Income from continuing operations	36,339			2,097			(3,142		)	35,294
Income (loss) from discontinued operations, net of tax	(527		)	1,045			—			518
Net income	$	35,812		$	3,142		$	(3,142	)	$	35,812

Condensed consolidating statement of operations

For the six months ended June 30, 2014

(Unaudited)



(in thousands)	Laredo			Laredo Midstream			Intercompany eliminations			Consolidated company
Total operating revenues	$	356,086		$	2,572		$	(2,304	)	$	356,354
Total operating costs and expenses	229,106			4,953			(2,304		)	231,755
Income (loss) from operations	126,980			(2,381		)	—			124,599
Interest expense, net	(59,366		)	—			—			(59,366		)
Other, net	(96,993		)	(77		)	2,458			(94,612		)
Loss from continuing operations before income tax	(29,379		)	(2,458		)	2,458			(29,379		)
Deferred income tax benefit	10,267			—			—			10,267
Loss from continuing operations	(19,112		)	(2,458		)	2,458			(19,112		)
Net loss	$	(19,112	)	$	(2,458	)	$	2,458		$	(19,112	)

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

Condensed consolidating statement of operations

For the six months ended June 30, 2013

(Unaudited)



(in thousands)	Laredo			Laredo Midstream			Intercompany eliminations			Consolidated company
Total operating revenues	$	340,965		$	5,364		$	(5,328	)	$	341,001
Total operating costs and expenses	242,859			1,551			(5,328		)	239,082
Income from operations	98,106			3,813			—			101,919
Interest expense, net	(51,265		)	—			—			(51,265		)
Other, net	13,089			(113		)	(6,042		)	6,934
Income from continuing operations before income tax	59,930			3,700			(6,042		)	57,588
Deferred income tax expense	(21,157		)	—			—			(21,157		)
Income from continuing operations	38,773			3,700			(6,042		)	36,431
Income (loss) from discontinued operations, net of tax	(1,552		)	2,342			—			790
Net income	$	37,221		$	6,042		$	(6,042	)	$	37,221

Condensed consolidating statement of cash flows

For the ~~three~~six months ended ~~March 31,~~June 30, 2014

(Unaudited)


(in thousands)	Laredo			Laredo Midstream			Intercompany eliminations			Consolidated company			Laredo			Laredo Midstream			Intercompany eliminations			Consolidated company
Net cash flows provided by operating activities	$	126,666		$	752		$	699		$	128,117
Net cash flows used in investing activities	(217,815		)	(752		)	(699		)	(219,266		)
Net cash flows provided by (used in) operating activities													$	240,880		$	(3,239	)	$	2,458		$	240,099
Change in investments between affiliates													(44,202		)	46,660			(2,458		)	—
Capital expenditures and other													(435,807		)	(43,421		)	—			(479,228		)
Net cash flows provided by financing activities	440,515			—			—			440,515			440,482			—			—			440,482
Net increase in cash and cash equivalents	349,366			—			—			349,366			201,353			—			—			201,353
Cash and cash equivalents at beginning of period	198,153			—			—			198,153			198,153			—			—			198,153
Cash and cash equivalents at end of period	$	547,519		$	—		$	—		$	547,519		$	399,506		$	—		$	—		$	399,506

Condensed consolidating statement of cash flows

For the ~~three~~six months ended ~~March 31,~~June 30, 2013

(Unaudited)


(in thousands)	Laredo			Laredo Midstream			Intercompany eliminations			Consolidated company			Laredo			Laredo Midstream			Intercompany eliminations			Consolidated company
Net cash flows provided by operating activities	$	62,345		$	3,615		$	(2,900	)	$	63,060		$	177,967		$	6,365		$	(6,042	)	$	178,290
Net cash flows used in investing activities	(198,670		)	(3,615		)	2,900			(199,385		)
Change in investments between affiliates													(11,266		)	5,224			6,042			—
Capital expenditures and other													(384,704		)	(11,589		)	—			(396,293		)
Net cash flows provided by financing activities	134,125			—			—			134,125			228,367			—			—			228,367
Net decrease in cash and cash equivalents	(2,200		)	—			—			(2,200		)
Net increase in cash and cash equivalents													10,364			—			—			10,364
Cash and cash equivalents at beginning of period	33,224			—			—			33,224			33,224			—			—			33,224
Cash and cash equivalents at end of period	$	31,024		$	—		$	—		$	31,024		$	43,588		$	—		$	—		$	43,588

2729

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

O—Subsequent events

1. ~~Amendment~~Leasehold acquisitions

Subsequent to ~~the Senior Secured Credit Facility~~

~~On May 8,~~June 30, 2014, the Company acquired or entered into agreements to acquire 8,777 net acres of additional leasehold interests in Reagan, Irion and Glasscock counties, primarily within the ~~Second Amendment to the Senior Secured Credit Facility~~, ~~pursuant to which, among other things, the borrowing base was increased to $1.0 billion with~~Company's core development area, for an aggregate ~~elected commitment amount~~purchase price of ~~$825.0~~$195.6 million.

~~2. New derivative contracts~~

~~Subsequent to March 31, 2014, the Company entered into the following new commodity contracts:~~

Aggregate
volumes

Swap
price
Floor price Ceiling price Contract period
Oil (volumes in Bbl):

Swap
933,300

$ 84.80

$ —

$ —

January 2016 - December 2016
Swap
640,500

$ 84.85

$ —

$ —

January 2016 - December 2016
Natural gas (volumes in MMBtu):
Collar⁽¹⁾
3,797,500
$ —
$ 4.00
$ 5.50
May 2014 - December 2014
Collar⁽¹⁾

20,440,000

$ —

$ 3.00

$ 5.95

January 2015 - December 2015
Collar⁽¹⁾
18,666,000
$ —
$ 3.00
$ 5.60
January 2016 - December 2016

~~(1)These natural gas derivatives are settled based on the Inside FERC West Texas Waha index price for the calculation period.~~

2830

Laredo Petroleum, Inc.

Condensed notes to the consolidated financial statements

(Unaudited)

P—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 and natural gas assets are presented below for the periods presented:


	Three months ended March 31,				Three months ended June 30,				Six months ended June 30,
(in thousands)	2014		2013		2014		2013		2014		2013
Property acquisition costs:											—
Proved	$	25	$	—	$	3,848	$	—	$	3,873	$	—
Unproved	7,280		—		2,645		—		9,925		—
Exploration	8,499		8,761		8,143		12,167		16,642		20,928
Development costs⁽¹⁾	188,313		157,316		220,240		165,416		408,553		322,732
Total costs incurred	$	204,117	$	166,077	$	234,876	$	177,583	$	438,993	$	343,660


(1)	The costs incurred for oil and natural gas development activities include $~~0.6~~0.9 million and $0.7 million in asset retirement obligations for the three months ended ~~March 31,~~June 30, 2014 and ~~2013.~~2013, respectively, and $1.5 million and $1.3 million for the six months ended June 30, 2014 and 2013, respectively.

2931

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the unaudited consolidated financial statements and condensed notes thereto included elsewhere in this Quarterly Report as well as our audited consolidated financial statements and notes thereto included in our 2013 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 (i) when used in the present tense, prospectively or as of December 31, 2013, ~~refers~~refer to Laredo Petroleum, Inc. together with Laredo Midstream and (ii) when used for historical periods from December 19, 2011 to December 30, 2013, ~~refers~~refer to Laredo Petroleum, Inc. and its subsidiaries, 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 exploration, development and acquisition of oil and natural gas properties primarily in the Permian Basin in West Texas. On August 1, 2013, we sold our properties in the Anadarko Granite Wash, Eastern Anadarko and Central Texas Panhandle (the "Anadarko Basin") in the Mid-Continent region of the United States.

Our financial and operating performance for the three months ended ~~March 31,~~June 30, 2014 included the following:

~~Oil~~Permian oil and natural gas sales of $~~173.2~~$182.9 million, compared to ~~$163.6~~$150.9 million for the three months ended ~~March 31,~~June 30, 2013;

~~Average~~Permian average daily production of ~~27,041~~28,653 BOE/D, compared to ~~34,722~~25,459 BOE/D for the three months ended ~~March 31,~~June 30, 2013; and

Adjusted EBITDA (a non-GAAP financial measure) of ~~$187.3~~$117.9 million,, compared to ~~$114.3~~$126.9 million for the three months ended ~~March 31,~~June 30, 2013.

Our financial and operating performance for the six months ended June 30, 2014 included the following:

Permian oil and natural gas sales of $356.1 million, compared to $290.9 million for the six months ended June 30, 2013;

Permian average daily production of 27,852 BOE/D, compared to 25,271 BOE/D for the six months ended June 30, 2013; and

Adjusted EBITDA (a non-GAAP financial measure) of $305.3 million, compared to $241.2 million for the six months ended June 30, 2013.

Recent developments

~~Notes Offering~~Leasehold acquisitions

Subsequent to June 30, 2014, we acquired or entered into agreements to acquire 8,777 net acres of additional leasehold interests in Reagan, Irion and Glasscock counties, primarily within our core development area, for an aggregate purchase price of $195.6 million.

Stockholders' changes

On ~~January 23,~~May 12, 2014, ~~we completed an offering~~Warburg Pincus Private Equity IX, L.P., Warburg Pincus X Partners, L.P. and Warburg Pincus Private Equity X O&G, L.P. (together, "Warburg Pincus") initiated a pro rata distribution (the "Distribution") to certain of ~~$450.0 million in aggregate principal amount~~the Warburg Pincus limited partners of ~~5 5/~~5,097,388 shares of our common stock. The Distribution represented 8% senior unsecured notes due 2022, and entered into an indenture among Laredo and Wells Fargo Bank, National Association, as trustee. The new senior unsecured notes will mature on January 15, 2022 with interest accruing at a rate of ~~5 5/8% per annum and payable semi-annually in cash in arrears on January 15 and July 15~~Warburg Pincus' holdings of ~~each year, commencing July 15, 2014. The new senior unsecured notes are guaranteed on a senior unsecured basis by Laredo Midstream.~~

~~The new senior unsecured notes were issued pursuant~~our common stock prior to the ~~indenture in a transaction exempt from the registration requirements~~Distribution, which was effective as of the Securities Act. The new senior unsecured notes were offered and sold only to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act. We received net proceedsMay 12, 2014. As of ~~$442.2 million from the offering, after deducting the initial purchasers’ discount and offering expenses. We plan to use the net proceeds~~August 4, 2014, Warburg Pincus owned 40.3% of ~~the offering for general working capital purposes.~~

In connection with the issuance of the new senior unsecured notes, we entered into a registration rights agreement with the initial purchasers of the new senior unsecured notes, pursuant to which we filed a registration statement with the SEC that became effective on April 22, 2014, with respect to an offer to exchange the January 2022 Notes for substantially identical notes (other than with respect to restrictions on transfer or any increase in annual interest rate) that are registered under the Securities Act. The offer to exchange the January 2022 Notes for substantially identical notes registered under the Securities Act commenced on April 22, 2014 and is scheduled to expire on May 21, 2014, unless extended. There is no guarantee we will be successful in exchanging any or all of the new senior notes.

~~Unwinding of commodity contract~~

In February 2014, we unwound a physical commodity contract with a Light Louisiana Sweet Argus index price and the associated oil basis swap financial derivative contract which hedged the differential between the Light Louisiana Sweet Argus and the Brent International Petroleum Exchange index oil prices. We received net proceeds of $76.7 million from the early termination of these contracts. We agreed to settle the contracts early due to our ~~counterparty's decision to exit the~~

~~physical commodity trading business. It is not our past practice nor do we expect to settle physical contracts financially in the future.~~

~~Amendment to the Senior Secured Credit Facility~~

~~On May 8, 2014, we entered into the Second Amendment to the Senior Secured Credit Facility~~, ~~pursuant to which, among other things, the borrowing base was increased to $1.0 billion with an aggregate elected commitment amount of $825.0 million.~~outstanding common stock.

Divestitures

On August 1, 2013, we completed the sale of oil and gas properties located in the Anadarko Basin, associated pipeline assets and various other related property and equipment (the "Anadarko Basin Sale") for a purchase price of $438.0 million. The purchase price (including the buyers' deposits) consisted of $400.0 million from certain affiliates of EnerVest, Ltd. and ~~$38.0~~

$38.0 million from other third parties in connection with the exercise of such third parties' preferential rights associated with certain of the oil and gas properties. Approximately $388.0 million of the purchase price, excluding closing adjustments, was allocated to oil and natural gas properties pursuant to the rules governing full cost accounting. After transaction costs and adjustments at closing reflecting an economic effective date of April 1, 2013, the net proceeds were $428.3 million, net of working capital adjustments. The net proceeds were used to pay off our Senior Secured Credit Facility and for working capital purposes.

Effective August 1, 2013, the operations and cash flows of these properties were eliminated from our ongoing operations and we do not have continued involvement in the operation of these properties. The oil and natural gas properties, which are a component of the assets sold, are not presented as discontinued operations pursuant to the rules governing full cost accounting for oil and gas properties. The results of operations of the associated pipeline assets and various other related property and equipment have been presented as results of discontinued operations, net of tax.

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 ~~March 31,~~June 30, 2014, we had assembled ~~202,973~~203,258 net acres in the Permian ~~Basin.~~Basin of which 145,423 net acres are located in our Permian-Garden City area.

Pricing

Our results of operations are heavily influenced by commodity prices. Prices for oil and natural gas can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for oil and natural gas, market uncertainty, economic conditions and a variety of additional factors. Since the inception of our oil and natural gas activities, commodity prices have experienced significant fluctuations, and additional changes in commodity prices may affect the economic viability of drilling projects, as well as the ~~economic~~ valuation and economic recovery of oil and natural gas reserves.

Our reserves are reported in two streams: crude oil and liquids-rich natural gas. The economic value of the natural gas liquids in our natural gas is included in the wellhead natural gas price. The unweighted arithmetic average first-day-of-the-month index prices for the prior 12 months ended ~~March 31,~~June 30, 2014 and ~~March 31,~~June 30, 2013 used to value our reserves were ~~$95.02~~$96.85 per Bbl for oil and ~~$3.90~~$4.03 per MMBtu for natural gas, and ~~$89.17~~$88.13 per Bbl for oil and ~~$2.84~~$3.32 per MMBtu for natural gas, respectively. The prices used to estimate proved reserves for all periods do not include derivative transactions. These prices were held constant throughout the life of the properties and have been adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

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

Sources of our revenue

Our revenues are derived from the sale of oil and natural gas within the continental United States and do not include the effects of derivatives. For the three months ended ~~March 31,~~June 30, 2014, our revenues were comprised of sales of ~~75%~~78% oil and ~~25%~~22% liquids-rich natural gas. For the six months ended June 30, 2014, our revenues were comprised of sales of 77% oil and 23% liquids-rich natural gas. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold and/or changes in commodity prices.

3133

Results of operations

Three and six months ended ~~March 31,~~June 30, 2014 as compared to the three and six months ended ~~March 31,~~June 30, 2013

Production, revenue and pricing

The following table sets forth information regarding production and revenue and average sales prices from continuing operations per BOE, for the periods presented:


	Three months ended March 31,						Three months ended June 30,						Six months ended June 30,
	2014			2013			2014			2013			2014			2013
Production data:
Oil (MBbl)	1,421			1,422			1,513			1,423			2,934			2,845
Natural gas (MMcf)	6,076			10,219			6,567			10,841			12,643			21,060
Oil equivalents (MBOE)⁽¹⁾⁽²⁾	2,434			3,125			2,607			3,230			5,041			6,355
Average daily production (BOE/D)⁽²⁾	27,041			34,722			28,653			35,494			27,852			35,110
% Oil	58		%	46		%	58		%	44		%	58		%	45		%
Revenues (in thousands):
Oil	$	130,427		$	116,800		$	142,919		$	126,852		$	273,346		$	243,651
Natural gas	42,787			46,825			39,953			50,196			82,740			97,022
Transportation and treating	96			80
Midstream service revenue							172			248			268			328
Total revenues	$	173,310		$	163,705		$	183,044		$	177,296		$	356,354		$	341,001
Average sales prices:
Oil, realized ($/Bbl)⁽³⁾	$	91.78		$	82.15		$	94.47		$	89.14		$	93.17		$	85.64
Natural gas, realized ($/Mcf)⁽³⁾	$	7.04		$	4.58		$	6.08		$	4.63		$	6.54		$	4.61
Average price, realized ($/BOE)⁽³⁾	$	71.17		$	52.35		$	70.13		$	54.81		$	70.63		$	53.62
Oil, hedged ($/Bbl)⁽⁴⁾	$	89.94		$	81.84		$	90.55		$	88.33		$	90.25		$	85.09
Natural gas, hedged ($/Mcf)⁽⁴⁾	$	6.92		$	4.73		$	6.04		$	4.55		$	6.46		$	4.64
Average price, hedged ($/BOE)⁽⁴⁾	$	69.79		$	52.70		$	67.75		$	54.19		$	68.73		$	53.47


(1)	Bbl equivalents are 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 and natural gas prices are the actual prices realized at the wellhead after all adjustments for natural gas liquid content, quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price 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 commodity hedging transactions on our average sales prices. Our calculation of such after effects include current period settlements of matured commodity 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.

3234

The following table presents cash settlements (paid) received for matured commodity 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 March 31,					Three months ended June 30,					Six months ended June 30,
(in thousands)	2014			2013		2014			2013		2014			2013
Cash settlements (paid) received for matured commodity derivatives:
Oil	$	(894	)	$	1,256	$	(4,337	)	$	946	$	(5,231	)	$	2,202
Natural gas	(537		)	2,521		(83		)	140		(620		)	2,661
Total	$	(1,431	)	$	3,777	$	(4,420	)	$	1,086	$	(5,851	)	$	4,863
Premiums paid attributable to contracts that matured during the respective period:
Oil	$	1,729		$	1,689	$	1,589		$	2,093	$	3,318		$	3,782
Natural gas	230			987		231			987		461			1,974
Total	$	1,959		$	2,676	$	1,820		$	3,080	$	3,779		$	5,756

The changes in volumes and prices shown in the table above caused the following changes to our oil and natural gas revenue between the three months ended ~~March 31,~~June 30, 2014 and 2013:


(in thousands)	Oil			Natural gas			Total net dollar effect of change			Oil			Natural gas			Total net dollar effect of change
2013 Revenue	$	116,800		$	46,825		$	163,625		$	126,852		$	50,196		$	177,048
Effect of changes in price	13,684			14,947			28,631			8,064			9,523			17,587
Effect of changes in volumes	(67		)	(18,974		)	(19,041		)	8,004			(19,788		)	(11,784		)
Other	10			(11		)	(1		)	(1		)	22			21
2014 Revenue	$	130,427		$	42,787		$	173,214		$	142,919		$	39,953		$	182,872

The changes in volumes and prices shown in the table above caused the following changes to our oil and natural gas revenue between the six months ended June 30, 2014 and 2013:



(in thousands)	Oil			Natural gas			Total net dollar effect of change
2013 Revenue	$	243,651		$	97,022		$	340,673
Effect of changes in price	22,092			24,402			46,494
Effect of changes in volumes	7,619			(38,800		)	(31,181		)
Other	(16		)	116			100
2014 Revenue	$	273,346		$	82,740		$	356,086

Our revenues are a function of oil and natural gas production volumes sold and average sales prices received for those volumes. The total increase in oil and natural gas revenues of $~~9.6~~5.8 million, or 6%3%, for the three months ended ~~March 31,~~June 30, 2014 as compared to the three months ended ~~March 31,~~June 30, 2013, is mainly due to a ~~54%~~31% increase in natural gas prices realized and a ~~12%~~6% increase in oil prices ~~realized.~~realized as well as a 6% increase in oil production. The increase in prices and oil volumes was offset by a ~~41%~~39% decrease in natural gas production due to the Anadarko Basin Sale. ~~Oil~~

The total increase in oil and natural gas revenues of $15.4 million, or 5%, for the six months ended June 30, 2014 as compared to the six months ended June 30, 2013, is mainly due to a 42% increase in natural gas prices realized and a 9% increase in oil prices realized as well as a 3% increase in oil production. The increase in prices and oil volumes was offset by a 40% decrease in natural gas production ~~remained consistent between quarters.~~due to the Anadarko Basin Sale.

3335

Costs and expenses

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


	Three months ended March 31,				Three months ended June 30,				Six months ended June 30,
(in thousands except for per BOE data)	2014		2013		2014		2013		2014		2013
Costs and expenses:
Lease operating expenses	$	21,785	$	22,442	$	20,179	$	22,185	$	41,964	$	44,627
Production and ad valorem taxes	12,450		11,445		13,160		9,722		25,610		21,167
Transportation and treating	594		108
Transportation and treating - affiliates	516		—
Drilling and production	251		674
Midstream service expense					1,526		697		2,371		1,479
Natural gas volume commitment - affiliates					588		139		1,104		139
General and administrative⁽¹⁾	27,654		19,634		29,552		20,495		57,206		40,129
Accretion of asset retirement obligations	415		394		422		410		837		804
Depletion, depreciation and amortization	49,607		64,503		53,056		66,234		102,663		130,737
Total costs and expenses	$	113,272	$	119,200	$	118,483	$	119,882	$	231,755	$	239,082
Average costs per BOE:
Lease operating expenses	$	8.95	$	7.18	$	7.74	$	6.87	$	8.32	$	7.02
Production and ad valorem taxes	5.12		3.66		5.05		3.01		5.08		3.33
Midstream service expense					0.59		0.22		0.47		0.23
General and administrative⁽¹⁾	11.36		6.28		11.34		6.35		11.35		6.31
Depletion, depreciation and amortization	20.38		20.64		20.35		20.51		20.37		20.57
Total	$	45.81	$	37.76	$	45.07	$	36.96	$	45.59	$	37.46

(1)

General and administrative includes non-cash stock-based compensation, net of amount capitalized, of ~~$4.3~~$6.4 million and ~~$3.2~~$4.5 million for the three months ended ~~March 31,~~June 30, 2014 and 2013, respectively, and $10.7 million and $7.7 million for the six months ended June 30, 2014 and 2013, respectively. Excluding stock-based compensation, net of amount capitalized, from the above metric results in general and administrative cost per BOE of $~~9.58~~8.88 and ~~$5.25~~$4.96 for the three months ended ~~March 31,~~June 30, 2014 and 2013, respectively, and $9.22 and $5.11 for the six months ended June 30, 2014 and 2013, respectively.

Lease operating expenses. Lease operating expenses, which include workover expenses, decreased by $~~0.7~~2.0 million, or 3%9%, compared to a 19% decrease in production, and $2.7 million, or 6%, compared to a 21% decrease in production, for the three and six months ended ~~March 31,~~June 30, 2014, respectively, compared to the same ~~period~~periods in 2013. The ~~decrease~~decreases in lease operating expenses was mainly a result of the Anadarko Basin Sale. On a per-BOE basis, lease operating expenses increased in total to $~~8.95~~7.74 and $8.32 per BOE for the three and six months ended ~~March 31,~~June 30, 2014, from ~~$7.18~~$6.87 and $7.02 per BOE for the same ~~period~~periods in 2013. The per-BOE increase was mainly due to ~~(i)~~ higher average lease operating expenses per-BOE on our higher oil-weighted Permian Basin production and lower total volumes following the Anadarko Basin ~~Sale and (ii) the implementation of best practices with respect to workover operations.~~Sale.

Production and ad valorem taxes. Production and ad valorem taxes increased by $~~1.0~~3.4 million, or 9%35%, and $4.4 million, or 21%, for the three and six months ended ~~March 31,~~June 30, 2014, respectively, compared to the same ~~period~~periods in 2013. Our production taxes are based on a percentage of our oil and natural gas revenue, and therefore increase in proportion to our oil and natural gas revenues. ~~Total~~On a per-BOE basis, production and ad valorem taxes increased due to lower production tax rates for the properties divested in the Anadarko Basin Sale.

Midstream service expense. Midstream service expense represents the cost to operate and maintain our (i) water storage, recycling and transportation facilities, (ii) oil and natural gas gathering and transportation systems and related facilities, (iii) centralized oil storage tanks and (iv) natural gas lift, rig fuel and compression infrastructure. These expenses increased by ~~14%~~$0.8 million, or 119%, and $0.9 million, or 60%, for the three and six months ended ~~March 31,~~June 30, 2014, respectively, compared to the same ~~period in 2013. Ad valorem taxes decreased by 5% for the three months ended March 31, 2014 compared to the same period~~periods in 2013, ~~primarily as a result~~due to our efforts to expand the midstream service component of ~~the Anadarko Basin Sale. This ad valorem tax decrease was partially offset by the ad valorem tax expense incurred for new wells drilled during the twelve-month period ended March 31, 2014.~~our business.

General and administrative ("G&A"). G&A expense, excluding stock-based compensation, increased by ~~$6.9~~$7.1 million, or ~~42%~~44%, and $14.0 million, or 43%, for the three and six months ended ~~March 31,~~June 30, 2014, respectively, compared to the same ~~period~~periods in 2013. Our employee base has continued to increase due to the growth of our business and accordingly, salaries, employee benefits and accrued bonuses have increased ~~$1.7~~by $3.9 million and $5.5 million for the three and six months ended ~~March 31,~~June 30, 2014, respectively, compared to the same ~~period~~periods in 2013. ~~Other significant increases were in professional~~Professional fees ~~of $2.6~~increased by $2.3 million and $4.9 million for the three and six months ended June 30, 2014, respectively, compared to the same periods in 2013. There was also a $3.0

million charitable ~~contributions of $3.1 million. The overall increase was offset by $1.3 million due to greater production income and capitalized stock-based compensation, salary and benefits.~~contribution pledged during the six months ended June 30, 2014, which will be paid in annual payments through 2024.

Stock-based compensation increased by ~~$1.1~~$3.2 million, or ~~35%~~71%, and $5.2 million, or 68%, for the three and six months ended ~~March 31,~~June 30, 2014, respectively, compared to the same ~~period~~periods in 2013, mainly due to the issuance of ~~1,068,053~~1,161,014 restricted stock awards at a weighted-average grant price of ~~$25.63~~$25.75 per share and 336,140 non-qualified restricted stock options to new and existing employees and non-employee directors in the ~~three~~six months ended ~~March 31,~~June 30, 2014 compared to the issuance of ~~1,166,295~~1,306,143 restricted stock awards at a weighted-average grant price of ~~$17.38~~$17.44 per share and 1,018,849 non-qualified restricted stock options to new and existing employees and ~~non-~~

~~employee~~non-employee directors in the same period in 2013. Additionally, during the ~~three~~six months ended ~~March 31,~~June 30, 2014, we issued 271,667 ~~performance share awards~~Performance Share Awards to management ~~which are accounted for as equity awards,~~and the associated expense amounted to ~~$0.2 million.~~$0.6 million and $0.8 million for the three and six months ended June 30, 2014, respectively. No comparable awards were issued during the ~~three~~six months ended ~~March 31,~~June 30, 2013. This increase in stock-based compensation was partially offset by management's decision to begin capitalizing a portion of stock-based compensation for employees who are directly involved in the acquisition ~~exploration~~ and ~~development~~exploration of our oil and natural gas properties into the full-cost pool in 2014. Capitalized stock-based compensation amounted to ~~$0.9~~$1.2 million and $2.2 million for the three and six months ended ~~March 31, 2014.~~

~~The cash-based 2012 and 2013 performance unit awards increased in fair value by $0.1 million for~~June 30, 2014, respectively. No amounts were capitalized during the ~~three~~six months ended March 31, 2014 and 2013, respectively, due to the quarterly re-measurement based on the performance of our stock price relative to our peer group utilized in the forward-looking Monte Carlo simulation.June 30, 2013.

The fair value of the restricted stock awards issued during 2014 and 2013 was calculated based on the value of our stock price on the date of grant in accordance with GAAP and is being recognized on a straight-line basis over the requisite service period of the awards. The fair value of our non-qualified restricted stock options was determined using a Black-Scholes valuation model in accordance with GAAP and is being recognized on a straight-line basis over the four-year requisite service period of the awards.

Our Performance Share Awards are accounted for as equity awards. The fair value of the ~~performance share awards~~Performance Share Awards issued during 2014 was based on a projection of the performance of our stock price relative to our peer group utilized in a forward-looking Monte Carlo simulation. The fair value of the ~~performance share awards~~Performance Share Awards will not be re-measured after the initial valuation of the awards and will be expensed on a straight-line basis over their three-year requisite service period. ~~Stock-based compensation expense related~~

Our 2012 and 2013 Performance Unit Awards are accounted for as liability awards. The fair value of the cash-based 2012 and 2013 Performance Unit Awards decreased in fair value by $1.0 million for each of the three and six months ended June 30, 2014, compared to the same periods in 2013, due to the quarterly re-measurement based on the performance ~~share awards amounted~~of our stock price relative to ~~$0.2 million for~~our peer group utilized in the ~~three months ended March 31, 2014.~~forward-looking Monte Carlo simulation.

See Notes B.12 and E 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 provides components of our DD&A expense from continuing operations for the periods presented:


	Three months ended March 31,				Three months ended June 30,				Six months ended June 30,
(in thousands except for per BOE data)	2014		2013		2014		2013		2014		2013
Depletion of proved oil and natural gas properties	$	47,742	$	63,284	$	50,955	$	64,847	$	98,697	$	128,131
Depreciation of pipeline assets	586		285
Depreciation of midstream service assets					918		504		1,692		978
Depreciation and amortization of fixed assets	1,279		934		1,183		883		2,274		1,628
Total DD&A	$	49,607	$	64,503	$	53,056	$	66,234	$	102,663	$	130,737
DD&A per BOE	$	20.38	$	20.64	$	20.35	$	20.51	$	20.37	$	20.57

DD&A decreased by $~~14.9~~13.2 million, or ~~23%~~20%, and by $28.1 million, or 21%, for the three and six months ended ~~March 31,~~June 30, 2014 as compared to the same ~~period~~periods in 2013. The ~~decrease is~~decreases are mainly a result of the Anadarko Basin Sale.

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


	Three months ended March 31,						Three months ended June 30,						Six months ended June 30,
(in thousands)	2014			2013			2014			2013			2014			2013
Non-operating income (expense):
Loss on derivatives:
Gain (loss) on derivatives:
Commodity derivatives, net	$	(31,112	)	$	(16,854	)	$	(63,125	)	$	23,975		$	(94,237	)	$	7,121
Interest rate derivatives, net	—			(6		)	—			(9		)	—			(15		)
Income (loss) from equity method investee	16			(64		)
Loss from equity method investee							(41		)	(49		)	(25		)	(113		)
Interest expense	(28,986		)	(25,349		)	(30,657		)	(25,943		)	(59,643		)	(51,292		)
Interest and other income	83			15			194			12			277			27
Write-off of deferred loan costs	(124		)	—			—			—			(124		)	—
Loss on disposal of assets, net	(21		)	—			(205		)	(59		)	(226		)	(59		)
Non-operating expense, net	$	(60,144	)	$	(42,258	)	$	(93,834	)	$	(2,073	)	$	(153,978	)	$	(44,331	)

Commodity derivatives. ~~Loss~~Gain on derivatives experienced during the three and six months ended June 30, 2013 became a loss on commodity derivatives ~~increased~~for the three and six months ended June 30, 2014. Gain (loss) on commodity derivatives decreased by $~~14.3~~87.1 million and $101.4 million for the three and six months ended ~~March 31,~~June 30, 2014, respectively, compared to the ~~three months ended March 31,~~same periods in 2013. Net cash settlements paid on matured commodity derivatives were ~~$1.4~~$4.4 million and $5.9 million for the three and six months ended ~~March 31,~~June 30, 2014, respectively, compared to net cash settlements received on

matured commodity derivatives of ~~$3.8~~$1.1 million and $4.9 million for the ~~three months ended March 31,~~same periods in 2013, which resulted in a decrease in cash flow of ~~$5.2 million. This decrease is~~$5.5 million and $10.7 million for the respective periods. These decreases are based on the cash settlement prices of our commodity derivatives compared to the prices specified in those contracts. Additionally, during the ~~three~~six months ended ~~March 31,~~June 30, 2014, we received $76.7 million in net proceeds from the early termination of our oil basis swap differential between the Light Louisiana Sweet Argus and the Brent International Petroleum Exchange index oil ~~prices.~~prices and the related physical contract. There were no comparable amounts in the ~~three~~six months ended ~~March 31,~~June 30, 2013.

The change in fair value of commodity derivatives still held decreased by ~~$85.8~~$81.6 million and $167.4 million for the three and six months ended ~~March 31,~~June 30, 2014, respectively, compared to the ~~three months ended March 31,~~same periods in 2013. This is mainly the result of the early settlement of our oil basis swap differential between the Light Louisiana Sweet Argus and the Brent International Petroleum Exchange index oil prices, which was entered into during the third quarter of 2013. The remainder of the change is a result of the changing relationships between our contract prices and the associated forward curves used to calculate the fair value of our commodity derivatives in relation to expected market prices. In general, we experience gains during periods of decreasing market prices and losses during periods of increasing market prices.

See Notes B.6, G and H 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 commodity derivatives.

Interest expense. Interest expense increased by $~~3.6~~4.7 million, or ~~14%~~18%, and by $8.4 million, or 16%, for the three and six months ended ~~March 31,~~June 30, 2014, respectively, compared to the ~~three months ended March 31,~~same periods in 2013. The increase is primarily due to the issuance of the January 2022 Notes, which was partially offset by the reduction in amount outstanding ofunder the Senior Secured Credit Facility and the related commitment fees on the unused portion of the banks' commitment on the Senior Secured Credit Facility.

The table below shows the change in the significant components of interest expense for the three and six months ended ~~March 31,~~June 30, 2014 as compared to the same ~~period~~periods in 2013:


(in thousands)	Three months ended March 31, 2014 compared to 2013			Three months ended June 30, 2014 compared to 2013			Six months ended June 30, 2014 compared to 2013
Changes in interest expense:
January 2022 Notes				$	6,328		$	11,180
Senior Secured Credit Facility, net of capitalized interest	$	(1,028	)	(1,614		)	(2,642		)
January 2022 Notes	4,852
Amortization of deferred loan costs	(94		)	(59		)	(153		)
Other	(93		)	59			(34		)
Total change in interest expense	$	3,637		$	4,714		$	8,351

Income tax expense. The fluctuations in income from continuing operations before income taxes is shown in the table below:


	Three months ended March 31,						Three months ended June 30,						Six months ended June 30,
(in thousands)	2014			2013			2014			2013			2014			2013
Income (loss) from continuing operations before income taxes	$	(106	)	$	2,247		$	(29,273	)	$	55,341		$	(29,379	)	$	57,588
Income tax expense	(107		)	(1,110		)
Income tax benefit (expense)							10,374			(20,047		)	10,267			(21,157		)
Income (loss) from continuing operations	$	(213	)	$	1,137		$	(18,899	)	$	35,294		$	(19,112	)	$	36,431
Effective tax rate							35		%	36		%	35		%	37		%

We expect the fiscal year 2014 annual effective tax rate, excluding discrete items, applicable to forecasted income before income taxes to be 35%. Significant factors that could impact the annual effective tax rate include management's assessment of certain tax matters, changes in certain non-deductible expenses and shortfalls related to restricted stock awards that vest and stock options that are exercised during the year. For the three months ended March 31, 2014 and 2013, the effective rate on income (loss) from continuing operations before income taxes was not meaningful due to the significant effect of discrete items on a relatively small loss from continuing operations. GAAP requires the application of the estimated annual effective rate in determining the interim period tax provision unless a rate cannot be reliably estimated, such as when a small change in pre-tax income or loss creates significant variations in the customary relationship between income tax expense or benefit and pre-tax income or loss in interim periods. In such a situation, the interim period tax provision should be based on actual year-to-date results.

The impact of discrete items is separately recognized in the quarter in which they occur. During the three and six months ended ~~March 31,~~June 30, 2014 and 2013, certain restricted stock awards vested at times when our stock price was lower than the fair value of those restricted stock awards at the time of grant. As a result, the income tax deduction related to such shares is less

than the expense previously recognized for book purposes. During the three and six months ended ~~March 31,~~June 30, 2014, certain restricted stock options were exercised. The income tax deduction related to the options' intrinsic value was less than the expense previously recognized for book purposes. For certain stock-based compensation awards that are expected to result in a tax deduction under existing tax law, a deferred tax asset is established as we recognize compensation cost for book purposes. Book compensation cost is determined on the grant date and recognized over the award's requisite service period, whereas the related tax deduction is measured on the vesting date for restricted stock and on the exercise date for stock options. The corresponding deferred tax asset also is measured on the grant date and recognized over the service period. As a result, there will almost always be a difference in the amount of compensation cost recognized for book purposes versus the amount of tax deduction that a company may receive. If the tax deduction exceeds the cumulative book compensation cost that we recognized, the tax benefit associated with any excess deduction will be considered an excess benefit or windfall and will be recognized as additional paid-in capital ("APIC"). If the tax deduction is less than the cumulative book compensation cost, the tax effect of the resulting difference is a deficiency or shortfall, and should be charged first to APIC, to the extent of our pool of windfall tax benefits, with any remainder recognized in income tax expense. We utilize a one-pool approach when accounting for the pool of windfall tax benefits in which employees and non-employees are grouped into a single pool.

As of ~~March 31,~~June 30, 2014 and 2013, we did not have any eligible windfall tax benefits to offset future shortfalls as no excess tax benefits have been recognized, therefore the tax impact of these shortfalls totaling $0.1 million and ~~$0.3~~$0.2 million for the three and six months ended ~~March 31,~~June 30, 2014, respectively, compared to $0.1 million and $0.4 million in the same periods in 2013, ~~respectively,~~ is included in income tax expense attributable to continuing operations for these respective periods. We expect income tax provisions for future reporting periods will be impacted by this stock compensation tax deduction shortfall; however, we cannot predict the stock compensation shortfall impact because of dependency upon future market price ~~performance~~ of our stock.

Liquidity and capital resources

Our primary sources of liquidity have been cash flows from operations, proceeds from equity offerings, proceeds from senior unsecured notes offerings, borrowings under our Senior Secured Credit Facility and proceeds from the Anadarko Basin Sale. Our primary ~~use~~uses of capital ~~has~~have been for the exploration, development and acquisition of oil and natural gas ~~properties.~~properties and for midstream infrastructure development.

As of ~~March 31,~~June 30, 2014, we had no amounts of principal outstanding under our Senior Secured Credit Facility and ~~$1.5~~$1.5 billion in senior unsecured notes. We had $~~812.5~~825.0 million available for borrowings under our Senior Secured Credit Facility and $~~547.5~~399.5 million in cash on hand for total available liquidity of ~~$1.4~~$1.2 billion as of ~~March 31,~~June 30, 2014. We believe such availability as well as cash flows from operations provide us with the ability to implement our planned ~~exploration and development activities.~~capital program.

As of ~~May 7,~~August 5, 2014 we had $1.5 billion in debt outstanding, ~~$812.5~~$825.0 million available for borrowings under our Senior Secured Credit Facility and ~~$493.7~~$274.4 million in cash on hand for total available liquidity of ~~$1.3~~$1.1 billion. ~~On May 8, 2014 the borrowing base and aggregate elected commitment amount increased to $1.0 billion and $825.0 million, respectively.~~

~~We expect, in the future, our~~

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

Cash flows

Our cash flows from continued and discontinued operations for the periods presented are as follows:


	Three months ended March 31,						Six months ended June 30,
(in thousands)	2014			2013			2014			2013
Net cash provided by operating activities	$	128,117		$	63,060		$	240,099		$	178,290
Net cash used in investing activities	(219,266		)	(199,385		)	(479,228		)	(396,293		)
Net cash provided by financing activities	440,515			134,125			440,482			228,367
Net increase (decrease) in cash and cash equivalents	$	349,366		$	(2,200	)
Net increase in cash and cash equivalents							$	201,353		$	10,364

For the ~~three~~six months ended ~~March 31,~~June 30, 2013, the results of operations of the pipeline assets and various other related property and equipment sold as a component of the Anadarko Basin Sale have been presented as results of discontinued operations, net of tax. We do not disclose discontinued operations separately from cash flows from continued operations due to the immateriality of the cash flows from discontinued operations. The absence of these discontinued operations will not materially affect future liquidity or capital resources.

Cash flows provided by operating activities

Net cash provided by operating activities was ~~$128.1~~$240.1 million and ~~$63.1~~$178.3 million for the ~~three~~six months ended ~~March 31,~~June 30, 2014 and 2013, respectively. The increase of ~~$65.1~~$61.8 million was largely due to the $76.7 million net proceeds received for early terminations of commodity derivative contracts. This increase was mainly offset by a reduction in depletion, depreciation and amortization, which resulted from the Anadarko Basin Sale.

Our operating cash flows are sensitive to a number of variables, the most significant of which are production levels and the volatility of oil, natural gas and natural gas liquids prices. Regional and worldwide economic activity, weather, infrastructure, capacity to reach markets, costs of operations and other variable factors significantly impact the prices of these commodities. These factors are not within our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see "Item 3. Quantitative and Qualitative Disclosures About Market Risk."

Cash flows used in investing activities

We used cash flows in investing activities of ~~$219.3~~$479.2 million and ~~$199.4~~$396.3 million for the ~~three~~six months ended ~~March 31,~~June 30, 2014 and 2013, respectively. The increase of ~~$19.9~~$82.9 million is mainly attributable to ~~acquisitions of mineral interests,~~capital expenditures for oil and natural gas properties, midstream service assets and contributions to our equity method ~~investee and additions to pipeline and gathering assets, offset by a decrease in purchases of other fixed assets.~~investee.

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


	Three months ended March 31,						Six months ended June 30,
(in thousands)	2014			2013			2014			2013
Capital expenditures:
Acquisition of oil and natural gas properties							$	(6,493	)	$	—
Acquisition of mineral interests	$	(7,305	)	$	—		(7,305		)	—
Investment in equity method investee	(11,300		)	(938		)	(19,471		)	(3,287		)
Oil and natural gas properties	(187,040		)	(187,813		)	(412,211		)	(375,901		)
Pipeline and gathering assets	(10,520		)	(4,046		)
Midstream service assets							(25,909		)	(8,302		)
Other fixed assets	(3,369		)	(6,588		)	(8,436		)	(8,803		)
Proceeds from dispositions of capital assets, net of costs	268			—			597			—
Net cash used in investing activities	$	(219,266	)	$	(199,385	)	$	(479,228	)	$	(396,293	)

Capital expenditure budget

Our board of directors approved a capital expenditure budget of approximately $1.0 billion for calendar year 2014, excluding acquisitions. We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted.

The amount, timing and allocation of capital expenditures are largely discretionary and within management's control. If oil and natural gas prices decline to levels below our acceptable levels, or costs increase to levels above our acceptable levels, we may choose to defer a portion of our budgeted capital expenditures until later periods in order 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. 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, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, contractual obligations, internally generated cash flow and other factors both within and outside our control.

Cash flows provided by financing activities

We had cash flows provided by financing activities of $440.5 million and ~~$134.1~~$228.4 million for the ~~three~~six months ended ~~March 31,~~June 30, 2014 and 2013, respectively. The increase of ~~$306.4~~$212.1 million was the result of the issuance of our January 2022 Notes ~~payments~~and proceeds from employee stock options exercises. These cash inflows were offset by increases in cash outflows for loan costs ~~an increase in the~~and cash flows to purchase of treasury stock to satisfy employee tax withholding obligations that arise upon the lapse of restrictions on restricted ~~stock and proceeds from employee stock option exercises.~~stock.

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


	Three months ended March 31,						Six months ended June 30,
(in thousands)	2014			2013			2014			2013
Cash flows from financing activities:
Borrowings on revolving credit facilities	$	—		$	135,000		$	—		$	230,000
Issuance of January 2022 Notes	450,000			—			450,000			—
Purchase of treasury stock	(3,274		)	(875		)	(3,556		)	(919		)
Proceeds from exercise of employee stock options	1,585			—			1,829			—
Payments for loan costs	(7,796		)	—			(7,791		)	(714		)
Net cash provided by financing activities	$	440,515		$	134,125		$	440,482		$	228,367

Debt

As of ~~March 31,~~June 30, 2014, we were a party only to our Senior Secured Credit Facility and the indentures governing our senior unsecured notes.

Senior Secured Credit Facility. As of ~~March 31,~~June 30, 2014, our Senior Secured Credit Facility, which matures November 4, 2018, had a maximum credit amount of $2.0 billion, ~~and~~ a borrowing base of $1.0 billion and an aggregate elected commitment amount of $~~812.5~~825.0 million. No amounts were outstanding under this facility as of such date.

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

As of March 31, 2014 and December 31, 2013, borrowings outstanding under our Senior Secured Credit Facility totaled zero. As of May 7, 2014, no amounts were outstanding under our Senior Secured Credit Facility and the amount available for borrowings was $812.5 million. On May 8, 2014 the borrowing base and aggregate elected commitment amount increased to $1.0 billion and $825.0 million, respectively.

Our Senior Secured Credit Facility is secured by a first-priority lien on our assets, including oil and natural gas properties constituting at least 80% of the present value of our proved reserves owned now or in the future. Our Senior Secured Credit Facility is subject to certain financial and non-financial ratios on a consolidated basis. We were in compliance with these ratios as of ~~March 31,~~June 30, 2014 and expect to be in compliance with them for the foreseeable future.

Senior unsecured notes. On January 23, 2014, we completed an offering of $450.0 million aggregate principal amount of 5 5/8% senior unsecured notes due 2022. 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 Laredo Midstream. Our January 2022 Notes were issued under and are governed by an indenture dated January 23, 2014 (the "2014 indenture"), among Laredo and Wells Fargo Bank, National Association, as trustee. The 2014 indenture contains customary terms, events of default and covenants relating to, among other things, the incurrence of debt, the payment of dividends or similar restricted payments, entering into transactions with affiliates and limitations on asset sales. Indebtedness

under our January 2022 Notes may be accelerated in certain circumstances upon an event of default as set forth in the 2014 indenture.

On April 27, 2012, we completed an offering of $500.0 million aggregate principal amount of 7 3/8% senior unsecured notes due 2022. 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 Laredo Midstream. Our May 2022 Notes were issued under and are governed by an indenture and supplement thereto, each dated April 27, 2012 (collectively, the "2012 indenture"), among Laredo and Wells Fargo Bank, National Association, as trustee. The 2012 indenture contains customary terms, events of default and covenants relating to, among other things, the incurrence of debt, the payment of dividends or similar restricted payments, entering into transactions with affiliates and limitations on asset sales. Indebtedness under our May 2022 Notes may be accelerated in certain circumstances upon an event of default as set forth in the 2012 indenture.

On January 20, 2011 and October 19, 2011, we completed the offerings of $350.0 million principal amount and $200.0 million principal amount, respectively, of 9 1/2% senior unsecured notes due 2019. The 2019 Notes will mature on February 15, 2019 and bear an interest rate of 9 1/2% per annum, payable semi-annually, in cash in arrears on February 15 and August 15 of each year. Our 2019 Notes are fully and unconditionally guaranteed on a senior unsecured basis by Laredo Midstream. Our 2019 Notes were issued under and are governed by an indenture dated January 20, 2011, among Laredo and Wells Fargo Bank, National Association, as trustee (the "2011 indenture"). The 2011 indenture contains customary terms, events of default and covenants relating to, among other things, the incurrence of debt, the payment of dividends or similar restricted payments, entering into transactions with affiliates and limitations on asset sales. Indebtedness under our 2019 Notes may be accelerated in certain circumstances upon an event of default as set forth in the 2011 indenture.

Refer to Note D of our audited consolidated financial statements included in the 2013 Annual Report and Note D of our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of the January 2022 Notes, May 2022 Notes, 2019 Notes and our Senior Secured Credit Facility.

As of ~~May 7,~~August 5, 2014, we had a total of $1.5 billion of senior unsecured notes outstanding.

Obligations and commitments

As of ~~March 31,~~June 30, 2014, our contractual obligations included our 2019 Notes, January 2022 Notes, May 2022 ~~Notes, 2019~~ Notes, drilling rig commitments, derivatives, performance unit liability awards, asset retirement obligations, office and equipment leases and a capital contribution commitment to our equity method investee. From December 31, 2013 to ~~March 31,~~June 30, 2014, the material changes in our contractual obligations included (i) ~~a decrease of $26.1 million on our principal and interest obligations for the 2019 Notes as a semi-annual interest payment was made in February 2014, (ii)~~ an increase of $652.5 million in principal and interest due to the January 2022 Notes offering, (ii) a decrease of $44.6 million on our principal and interest obligations for the 2019 Notes and May 2022 Notes, as semi-annual interest payments were made in February and May 2014, (iii) a decrease in our outstanding capital contribution commitment to our equity method investee due to a payment by us of ~~$9.7~~$19.5 million towards the construction of a pipeline by MPC, (iv) a decrease of $6.0 million for short-term drilling rig commitments (on contracts other than those on a well-by-well basis), ~~(iv)~~(v) a decrease of ~~$1.9~~$3.7 million for deferred premiums due on commodity derivative contracts as a result of payments made and early terminations, ~~(v)~~(vi) an increase of ~~$0.1~~$2.1 million in our total asset retirement obligation due to the drilling of new wells with associated asset retirement cost and accretion and (vii) an increase of $1.2 million for the estimated total liability payable for our performance unit awards issued under our LTIP, ~~as of March 31, 2014,~~ which will be paid in the first quarter of 2015 for the February 2012 grants and the first quarter of 2016 for the February 2013 grants, (vi) an increase of $1.0 million in our total asset retirement obligation due to the drilling of new wells with associated asset retirement cost and accretion and (vii) a decrease in our outstanding capital contribution commitment to our equity method investee due to a payment by us of ~~$11.3 million~~ ~~towards the construction of a pipeline by MPC.~~grants.

Refer to Notes B, D, E, G, H and L to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our ~~asset retirement obligations,~~long-term debt, equity method investment, drilling contract commitments, deferred premiums on our commodity derivatives, asset retirement obligations and performance unit ~~awards, long-term debt, drilling contract commitments and equity method investment.~~awards.

Non-GAAP financial measures

The non-GAAP financial measure of Adjusted EBITDA, as defined by us, may not be comparable to similarly titled measures used by other companies. Therefore, this non-GAAP measure should be considered in conjunction with income from continuing operations and other performance measures prepared in accordance with GAAP, such as operating income 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, operating income or any other GAAP measure of liquidity or financial performance.

Adjusted EBITDA

Adjusted EBITDA is a non-GAAP financial measure that we define as net income or loss plus adjustments for interest expense, depletion, depreciation and amortization, impairment of long-lived assets, write-off of deferred loan costs, bad debt expense, gains or losses on disposal of assets, gains or losses on derivatives, cash settlements of matured commodity derivatives, cash settlements on early terminated derivatives, premiums paid for derivatives that matured during the period, non-cash stock-based compensation and income tax expense or benefit. 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, 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.

The following presents a reconciliation of net income (loss) for continuing and discontinued operations to Adjusted EBITDA:


	Three months ended March 31,						Three months ended June 30,						Six months ended June 30,
(in thousands)	2014			2013			2014			2013			2014			2013
Net income (loss)	$	(213	)	$	1,409		$	(18,899	)	$	35,812		$	(19,112	)	$	37,221
Plus:
Interest expense	28,986			25,349			30,657			25,943			59,643			51,292
Depletion, depreciation and amortization	49,607			65,130			53,056			66,234			102,663			131,364
Write-off of deferred loan costs	124			—			—			—			124			—
Loss on disposal of assets, net	21			—			205			59			226			59
Loss on derivatives, net	31,112			16,860
(Gain) loss on derivatives, net							63,125			(23,966		)	94,237			(7,106		)
Cash settlements (paid) received for matured commodity derivatives, net	(1,431		)	3,777			(4,420		)	1,086			(5,851		)	4,863
Cash settlements received for early terminations of derivatives, net	76,660			—			—			—			76,660			—
Premiums paid for derivatives that matured during the period⁽¹⁾	(1,959		)	(2,676		)	(1,820		)	(3,080		)	(3,779		)	(5,756		)
Non-cash stock-based compensation, net of amount capitalized	4,329			3,217			6,396			4,463			10,725			7,680
Deferred income tax expense	107			1,263
Deferred income tax (benefit) expense							(10,374		)	20,338			(10,267		)	21,601
Adjusted EBITDA	$	187,343		$	114,329		$	117,926		$	126,889		$	305,269		$	241,218


(1)	Reflects premiums incurred previously or upon settlement that are attributable to instruments settled in the respective periods presented.

Critical accounting policies and estimates

The discussion and analysis of our financial condition and results of operations are based upon our unaudited consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our unaudited consolidated financial statements. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our 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 and natural gas reserve quantities and standardized measure of future net revenues, (iii) revenue recognition, (iv) fair value of assets acquired and liabilities assumed in an acquisition, (v) impairment of oil and natural gas properties, ~~(v)~~(vi) asset retirement obligations, ~~(vi)~~(vii) valuation of derivatives and deferred premiums, ~~(vii)~~(viii) valuation of stock-based compensation and performance unit compensation and ~~(viii)~~(ix) estimation of income taxes. 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 the estimates, as additional information becomes known.

There have been no material changes in our critical accounting policies and procedures during the ~~three~~six months ended ~~March 31,~~June 30, 2014. 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 2013 Annual Report. Additionally, see Note B 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

In May 2014, the FASB issued a comprehensive new revenue recognition standard that supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities—Oil and Gas—Revenue Recognition. The core principle of the new guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for transferring those goods or services. The new standard also requires significantly expanded disclosure regarding the qualitative and quantitative information of an entity's nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The standard creates a five-step model that requires companies to exercise judgment when considering the terms of a contract and all relevant facts and circumstances. The standard allows for several transition methods: (a) a full retrospective adoption in which the standard is applied to all of the periods presented, or (b) a modified retrospective adoption in which the standard is applied only to the most current period presented in the financial statements, including additional disclosures of the standard’s application impact to individual financial statement line items. This standard is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. We are currently evaluating this standard and our existing revenue recognition policies to determine which contracts in the scope of the guidance will be affected by the new requirements and what impact they will have on our consolidated financial statements upon adoption of this standard.

In April 2014, the FASB issued guidance on reporting discontinued operations and disclosures of disposals of components of an entity. The guidance changes the criteria for reporting discontinued operations, ~~while enhancing disclosures in this area and~~including raising the threshold for a disposal to qualify as discontinued operations. The guidance also requires entities to provide additional disclosure about discontinued operations as well as disposal transactions that do not meet the discontinued operations criteria. The pronouncement is effective for annual and interim periods beginning after December 15, 2014. Early adoption is permitted for disposals or for assets classified as held for sale that have not been reported in previously issued financial statements. We ~~are currently evaluating the provisions of~~elected to early adopt this guidance in the second quarter of 2014 on a prospective basis, and ~~assessing~~ the ~~impact, if~~adoption did not have an effect on our consolidated financial statements.

jurisdiction to settle any ~~it may~~additional income taxes that would result from the disallowance of a tax position, or (ii) the tax law of the applicable jurisdiction does not require the entity to use, and the entity does not intend to use, the deferred tax asset for such purpose. In those situations the unrecognized tax benefit should be presented in the financial statements as a liability and should not be combined with deferred tax assets. We adopted this guidance on January 1, 2014, and the adoption did not have an effect on our consolidated financial statements.

Off-balance sheet arrangements

Currently, we do not have any off-balance sheet arrangements other than operating leases, which are included in "Obligations and commitments."

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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" refers to the risk of loss arising from adverse changes in oil and natural gas prices and 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 and natural gas prices, we use commodity derivatives, such as collars, swaps, puts and basis swaps to hedge price risk associated with a significant portion of our anticipated oil and natural gas production. By removing a majority 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 value of our commodity derivatives using an independent third-party valuation and recognize the associated gain or loss in our consolidated statements of operations.

Our hedged positions as of ~~March 31,~~June 30, 2014 are as follows:


	Remaining year 2014			Year 2015		Year 2016		Total			Remaining year 2014			Year 2015		Year 2016		Total
Oil⁽¹⁾
Total volume hedged with ceiling price (Bbl)	3,831,997			6,557,020		1,860,000		12,249,017			2,844,998			7,229,020		4,129,800		14,203,818
Weighted-average ceiling price ($/Bbl)	$	100.03		$	95.40	$	91.37	$	96.24		$	100.38		$	95.51	$	90.36	$	94.99
Total volume hedged with floor price (Bbl)	4,236,997			7,013,020		1,860,000		13,110,017			3,114,998			7,685,020		4,129,800		14,929,818
Weighted-average floor price ($/Bbl)	$	88.01		$	79.50	$	80.00	$	82.32		$	89.45		$	80.99	$	81.84	$	82.99
Natural gas⁽²⁾
Total volume hedged with ceiling price (MMBtu)	12,150,000			8,160,000		—		20,310,000			10,964,000			28,600,000		18,666,000		58,230,000
Weighted-average ceiling price ($/MMBtu)	$	5.02		$	6.00	$	—	$	5.41		$	5.14		$	5.96	$	5.60	$	5.69
Total volume hedged with floor price (MMBtu)	12,150,000			8,160,000		—		20,310,000			10,964,000			28,600,000		18,666,000		58,230,000
Weighted-average floor price ($/MMBtu)	$	3.54		$	3.00	$	—	$	3.32		$	3.66		$	3.00	$	3.00	$	3.12
Oil basis⁽³⁾
Total volume hedged (Bbl)	1,650,000			—		—		1,650,000			1,104,000			—		—		1,104,000
Weighted-average price ($/Bbl)	$	(1.00	)	$	—	$	—	$	(1.00	)	$	(1.00	)	$	—	$	—	$	(1.00	)


(1)	Oil derivatives are settled based on the average of the daily settlement prices for the First Nearby Month of the NYMEX Light Sweet Crude Oil Futures Contract for each NYMEX Trading Day during each month. Weighted-average prices include the West Texas Intermediate Argus Midland and the West Texas Intermediate Argus Cushing basis swap.


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


(3)	The associated oil basis swap is settled on the differential between the West Texas Intermediate Argus Midland and the West Texas Intermediate Argus Cushing index oil prices.

The fair values of our commodity derivatives are largely determined by estimates of the forward curves of the relevant price indices. As of ~~March 31,~~June 30, 2014, a 10% change in the forward curves associated with our commodity derivatives would have changed our net positions byto the following amounts:


(in thousands)	10% Increase			10% Decrease		10% Increase			10% Decrease
Commodity derivatives	$	(112,411	)	$	54,755	$	(201,005	)	$	23,208

As of ~~March 31,~~June 30, 2014 and December 31, 2013, the fair values of our open derivative contracts were a liability of ~~$22.4~~$79.3 million and an asset of $82.1 million. Refer to Notes G and H of our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional disclosures regarding our derivatives.

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Interest rate risk

Our Senior Secured Credit Facility bears interest at a floating rate and, as of ~~March 31,~~June 30, 2014, we had no indebtedness outstanding on our Senior Secured Credit Facility. Our 2019 Notes, January 2022 Notes and May 2022 Notes bear fixed interest rates and we had $550.0 million (excluding the remaining premium of $~~1.5~~1.4 million), $450.0 million and $500.0 million outstanding, respectively, as of ~~March 31,~~June 30, 2014, as shown in the table below.



	Expected maturity date
(in millions except for interest rates)	2014			2015			2016			2017			2018			Thereafter			Total
2019 Notes - fixed rate	$	—		$	—		$	—		$	—		$	—		$	550.0		$	550.0
Average interest rate	—		%	—		%	—		%	—		%	—		%	9.5		%	9.5		%
January 2022 Notes - fixed rate	$	—		$	—		$	—		$	—		$	—		$	450.0		$	450.0
Average interest rate	—		%	—		%	—		%	—		%	—		%	5.625		%	5.625		%
May 2022 Notes - fixed rate	$	—		$	—		$	—		$	—		$	—		$	500.0		$	500.0
Average interest rate	—		%	—		%	—		%	—		%	—		%	7.375		%	7.375		%
Senior Secured Credit Facility - variable rate	$	—		$	—		$	—		$	—		$	—		$	—		$	—
Average interest rate	—		%	—		%	—		%	—		%	—		%	—		%	—		%

Counterparty and customer credit risk

Our principal exposures to credit risk are through (i) receivables resulting from the sale of our oil and natural gas production ($~~59.0~~68.5 million as of ~~March 31,~~June 30, 2014) which we market to energy marketing companies and refineries, (ii) joint interest receivables ($~~24.0~~23.3 million as of ~~March 31,~~June 30, 2014) and (iii) the receivables from derivatives ($~~4.5~~1.4 million as of ~~March 31,~~June 30, 2014).

We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. We do not 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, who are each also lenders in our Senior Secured Credit Facility. The terms of the ISDA Agreements provide us and the counterparties with rights of offset upon the occurrence of defined acts of default by either us or a counterparty to a derivative, whereby the party not in default may offset all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party.

Refer to Note I 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 Securities Exchange Act of 1934, as amended (the "Exchange Act"), was performed under the supervision and with the participation of Laredo’s management, including our principal executive officer and principal financial officer. Based on that evaluation, these officers concluded that Laredo’s disclosure controls and procedures were effective as of ~~March 31,~~June 30, 2014. Our disclosure controls and other procedures are designed to provide reasonable assurance that the information required to be disclosed in the reports we file and submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to Laredo’s management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

Evaluation of changes in internal control over financial reporting

There were no changes in our internal control over financial reporting during the quarter ended ~~March 31,~~June 30, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

4548

PART II

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

In addition to the other information set forth in this Quarterly Report, you should carefully consider the risks discussed in our 2013 Annual Report. There have been no material changes in our risk factors from those described in the 2013 Annual Report. The risks described in the 2013 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
January 1, 2014 - January 31, 2014 1,398
$ 25.68
—
—
February 1, 2014 - February 28, 2014 121,410
$ 25.82
—
—
March 1, 2014 - March 31, 2014 3,723
$ 25.09
—
—



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, 2014 - April 30, 2014	5,456	$	28.28	—	—
May 1, 2014 - May 31, 2014	1,661	$	27.69	—	—
June 1, 2014 - June 30, 2014	2,804	$	28.85	—	—


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

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

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

Pursuant to Section 13(r) of the Securities Exchange Act of 1934, we may be required to disclose in our annual and quarterly reports to the SEC, whether we or any of our ~~"affiliates"~~“affiliates” knowingly engaged in certain activities, transactions or dealings relating to Iran or with certain individuals or entities targeted by ~~U.S.~~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"~~“affiliate” broadly, it includes any entity under common ~~"control"~~“control” with ~~us. The~~us (and the term ~~"control"~~“control” is also construed broadly by the ~~SEC.~~SEC).

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

The disclosure below relates solely to activities conducted by SAMIH and its non-U.S. affiliates that may be deemed to be under common ~~"control"~~“control” with us. The disclosure does not relate to any activities conducted by us or by WP and does not involve our or WP’s management. Neither weWP nor ~~WP have~~the Company has had any involvement in or control over the disclosed activities of SAMIH, and neither weWP nor WPthe Company has independently verified or participated in the preparation of the disclosure. Neither weWP nor ~~WP are~~the Company is representing to the accuracy or completeness of the disclosure nor do weWP or WPwe undertake any obligation to correct or update it.

We understand that SAMIH’s affiliates intend to disclose in their next annual or quarterly SEC report that an Iranian national, resident in the U.K., who is currently ~~designated~~classified by the U.S. under the Iranian Financial Sanctions Regulations and the ~~NPWMD~~Non-Proliferation of Weapons of Mass Destruction designation, holds two investment accounts with Santander Asset Management UK Limited. The accounts have remained frozen throughout 2013 and the first ~~quarter~~half of 2014. The investment returns are being automatically reinvested, and no disbursements have been made to the customer. ~~Total~~In the first half of 2014, the total revenue for the Santander Group in connection with the investment accounts was ~~£23,017 whilst~~£23,200, while net profits ~~in the first quarter 2014~~ were negligible relative to the overall profits of Banco Santander, S.A.

4650

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			Amended and Restated Bylaws of Laredo Petroleum Holdings, Inc. (incorporated by reference to Exhibit 3.2 of Laredo’s Current Report on Form 8-K (File No. 001-35380) filed on December 22, 2011).

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).

~~4.2~~4.2*			Amended and Restated Indenture, dated as of ~~January 23,~~June 24, 2014, among Laredo Petroleum, Inc., Laredo Midstream Services, LLC, and Wells Fargo Bank, National Association, as ~~trustee (incorporated by reference to Exhibit 4.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on January 24, 2014).~~trustee.

~~4.3~~4.3*			~~Registration Rights Agreement,~~ Amended and Restated Supplemental Indenture, dated as of ~~January 23,~~June 24, 2014, among Laredo Petroleum, Inc., Laredo Midstream Services, LLC, and ~~the initial purchasers (incorporated by reference to Exhibit 10.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on January 24, 2014).~~Wells Fargo Bank, National Association, as trustee.

10.1			First Amendment to Fourth Amended and Restated Credit Agreement, dated as of January 31, 2014, among Laredo Petroleum, Inc., Wells Fargo Bank, N.A., as administrative agent, Laredo Midstream Services, LLC and the banks signatory thereto (incorporated by reference to Exhibit 10.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on February 4, 2014).

~~10.2~~			Second Amendment to Fourth Amended and Restated Credit Agreement, dated as of May 8, 2014, among Laredo Petroleum, Inc., Wells Fargo Bank, N.A., as administrative agent, Laredo Midstream Services, LLC and the banks signatory thereto (incorporated by reference to Exhibit 10.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on May 8, 2014).

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

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

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

101.INS*			XBRL Instance Document.

101.CAL*			XBRL Schema Document.

101.SCH*			XBRL Calculation Linkbase Document.

101.DEF*			XBRL Definition Linkbase Document.

101.LAB*			XBRL Labels Linkbase Document.

101.PRE*			XBRL Presentation Linkbase Document.

* Filed herewith.

** Furnished herewith.

4751

SIGNATURES

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



	LAREDO PETROLEUM, INC.

Date: ~~May 8,~~August 7, 2014	By:	/s/ Randy A. Foutch
		Randy A. Foutch
		Chairman and Chief Executive Officer
		(principal executive officer)

Date: ~~May 8,~~August 7, 2014	By:	/s/ Richard C. Buterbaugh
		Richard C. Buterbaugh
		Executive Vice President and Chief Financial Officer
		(principal financial officer)

	By:
Date: ~~May 8,~~August 7, 2014	By:	/s/ Michael T. Beyer
		Michael T. Beyer
		Vice President - Controller and Chief Accounting Officer
		(principal accounting officer)

4852

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			Amended and Restated Bylaws of Laredo Petroleum Holdings, Inc. (incorporated by reference to Exhibit 3.2 of Laredo’s Current Report on Form 8-K (File No. 001-35380) filed on December 22, 2011).

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).

~~4.2~~4.2*			Amended and Restated Indenture, dated as of ~~January 23,~~June 24, 2014, among Laredo Petroleum, Inc., Laredo Midstream Services, LLC, and Wells Fargo Bank, National Association, as ~~trustee (incorporated by reference to Exhibit 4.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on January 24, 2014).~~trustee.

~~4.3~~4.3*			~~Registration Rights Agreement,~~Amended and Restated Supplemental Indenture, dated as of ~~January 23,~~June 24, 2014, among Laredo Petroleum, Inc., Laredo Midstream Services, LLC, and ~~the initial purchasers (incorporated by reference to Exhibit 10.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on January 24, 2014).~~Wells Fargo Bank, National Association, as trustee.

10.1			First Amendment to Fourth Amended and Restated Credit Agreement, dated as of January 31, 2014, among Laredo Petroleum, Inc., Wells Fargo Bank, N.A., as administrative agent, Laredo Midstream Services, LLC and the banks signatory thereto (incorporated by reference to Exhibit 10.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on February 4, 2014).

~~10.2~~			Second Amendment to Fourth Amended and Restated Credit Agreement, dated as of May 8, 2014, among Laredo Petroleum, Inc., Wells Fargo Bank, N.A., as administrative agent, Laredo Midstream Services, LLC and the banks signatory thereto (incorporated by reference to Exhibit 10.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on May 8, 2014).

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

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

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

101.INS*			XBRL Instance Document.

101.CAL*			XBRL Schema Document.

101.SCH*			XBRL Calculation Linkbase Document.

101.DEF*			XBRL Definition Linkbase Document.

101.LAB*			XBRL Labels Linkbase Document.

101.PRE*			XBRL Presentation Linkbase Document.

* Filed herewith.

** Furnished herewith.

4953



(in thousands)	Three months ended March 31, 2014			Year ended December 31, 2013
Liability at beginning of period	$	21,743		$	21,505
Liabilities added due to acquisitions, drilling and other	576			2,709
Accretion expense	415			1,475
Liabilities settled upon plugging and abandonment	(1		)	(226		)
Liabilities removed due to Anadarko Basin Sale	—			(7,801		)
Revision of estimates	—			4,081
Liability at end of period	$	22,733		$	21,743



	Aggregate volumes	Swap price		Floor price		Ceiling price		Contract period
Oil (volumes in Bbl):
Swap	933,300	$	84.80	$	—	$	—	January 2016 - December 2016
Swap	640,500	$	84.85	$	—	$	—	January 2016 - December 2016
Natural gas (volumes in MMBtu):
Collar⁽¹⁾	3,797,500	$	—	$	4.00	$	5.50	May 2014 - December 2014
Collar⁽¹⁾	20,440,000	$	—	$	3.00	$	5.95	January 2015 - December 2015
Collar⁽¹⁾	18,666,000	$	—	$	3.00	$	5.60	January 2016 - December 2016