Laredo Petroleum, Inc. - FORM 8-K - EX-99.1 - EXHIBIT

Attached files

file	filename
8-K - 8-K - Laredo Petroleum, Inc.	a3q8kerpr.htm

EXHIBIT 99.1

15 West 6^th Street, Suite, 1800 · Tulsa, Oklahoma 74119 · (918) 513-4570 · Fax: (918) 513-4571

www.laredopetro.com

Laredo Petroleum Holdings, Inc. Announces 2013 Third-Quarter

Financial and Operating Results

TULSA, OK - November 7, 2013 - Laredo Petroleum Holdings, Inc. (NYSE: LPI) (“Laredo” or “the Company”) today announced third-quarter results, reporting net income attributable to common stockholders of $12.5 million, or $0.09 per diluted share. Adjusted net income, a non-GAAP financial measure, for the quarter was $20.7 million, or $0.15 per diluted share and Adjusted EBITDA, a non-GAAP financial measure, for the quarter was $139.8 million. (Please see supplemental financial information at the end of this news release for reconciliations of these non-GAAP financial measures.)

2013 Third-Quarter Highlights


•	Increased Permian production volume to 24,332 barrels of oil equivalent (“BOE”) per day on a two-stream basis, up 17% from the third quarter of 2012


•	Increased Adjusted EBITDA to $139.8 million, up 29% from the third quarter of 2012 and up 10% from the second quarter of 2013


•	Increased cash margin to $46.39 per BOE, up 27% from third-quarter 2012, driven by increasing oil production that represented 49% of overall production


•	Drilled and began completions on the Company’s first stacked lateral test of vertical spacing with three horizontal wells drilled on the same pad into the Upper, Middle and Lower Wolfcamp zones


•	Recorded the Company’s best horizontal Cline 30-day average initial production (“IP”) rate from the Glass-Glass 10 #153H producing 1,052 BOE per day (“BOE/D”) on a two-stream basis


•	Closed the sale of the Anadarko Basin properties with a sales price of approximately $438 million


•	Raised approximately $298 million in a follow-on equity offering, increasing total liquidity to approximately $1.1 billion

“This quarter Laredo continued its disciplined advance in the understanding and development of our Permian-Garden City asset,” said Randy A. Foutch, Laredo Chairman and Chief Executive Officer. “We maintained our data-driven approach to field development by drilling our first multi-well pad of stacked horizontal laterals into the Upper, Middle and Lower Wolfcamp zones. This test of vertical spacing between zones, coupled with our previous horizontal spacing test, extensive modeling and petrophysical analysis, provides valuable data that we are using to optimize the development of this phenomenal asset.”

“Operationally, the Company continues to have outstanding well results in the four initial zones confirmed for horizontal development. We expect to begin testing additional zones later this year and in 2014, while continuing to develop the infrastructure necessary to support multi-well pad drilling to efficiently develop this vast concentrated resource. With the closing of the sale of our Anadarko Basin assets and the capital raised in the follow-on equity offering, Laredo is very well positioned to fund an expanding development program to grow production and maximize the value of our Permian-Garden City acreage.”

Operational Update

During the third quarter, Laredo set a company record for both a peak 24-hour and a 30-day average IP rate for a Cline horizontal well. The Glass-Glass 10 #153H achieved a peak 24-hour rate of 1,455 BOE/D and a 30-day average IP of 1,052 BOE/D on a two-stream basis. In the third quarter, the Company completed 18 vertical wells and five horizontal wells that reached a peak rate and have 30 days of production history. The results for those horizontal wells are as follows:



Well Name	Lateral Length	No. of Frac Stages	Completion Date	Peak 24-Hr IP	Avg. 30-Day IP
	(feet)			(Two-Stream BOE/D)
Upper Wolfcamp
Glass-Glass 10 #152HU	7,058	28	Jul-13	844	697
Bodine-C-30-1HU	7,001	25	Sep-13	1,420	731
Upper Wolfcamp
Sugg-B-131/Holt E 2HM	7,600	25	Sep-13	1,080	555
Bodine-C-30-2HM	6,958	25	Sep-13	1,035	550
Cline
Glass-Glass 10 #153H	6,933	25	Aug-13	1,455	1,052

Not included in the results above are horizontal wells from the Company’s first stacked lateral test. The Sugg A 171 1HU, Sugg A 171 2HM and Sugg A 171 3HL were completed in mid-October and achieved a combined two-stream, peak 24-hour production rate of 3,318 BOE/D and although 30-day averages have not been achieved, they continue to perform in-line with their respective type curves.

In late September the Company added a fifth horizontal rig and expects to add a sixth horizontal rig by year-end. Both rigs will be primarily drilling multi-well pads, with the fifth rig impacting production beginning in the first quarter of 2014 and the sixth rig to begin impacting production in the second quarter of 2014. In addition to accelerating development in currently delineated areas, Laredo also intends to horizontally test extensional acreage and additional zones. In the fourth quarter it is anticipated that a

Middle Wolfcamp horizontal well will be spud in northern Glasscock County and a horizontal well in the Lower Spraberry zone will be drilled in Reagan County.

In the Permian Basin, third-quarter 2013 average daily production was 24,332 BOE/D, up 17% from third-quarter 2012. Total average daily production company-wide was 28,361 BOE/D compared to 30,835 BOE/D in the prior-year quarter, down 8%, reflecting the sale of the Anadarko Basin properties that closed on August 1, 2013. As the Company transitioned to a pure-play Permian Basin producer, with only one month of production from the Anadarko Basin during the quarter, oil as a percentage of total production rose to 49% of total production for the quarter, up from 42% in the prior-year quarter.

The Company’s average realized price increased to $65.48 per BOE, up from $50.68 in the third quarter of 2012. Cash margin for third-quarter 2013 increased 27% from the prior-year period to $46.39 per BOE, driven by higher oil production as a percentage of total production and higher commodity prices.

2013 Capital Program

During the third quarter of 2013, Laredo invested approximately $193.9 million in total capital expenditures, including approximately $36.7 in bolt-on acquisitions in Garden City, with approximately $148.9 dedicated to development activities.

Liquidity

At September 30, 2013, the Company had approximately $265 million in cash and cash equivalents and an undrawn senior secured credit facility, which had a borrowing base of $825 million, resulting in total liquidity of approximately $1.1 billion. On November 4, 2013, the Company’s senior secured credit facility was amended to increase the borrowing base to $925 million with an aggregate elected commitment amount of $825 million and the maturity was extended to November 2018.

Guidance

The table below reflects the Company’s guidance for the fourth quarter of 2013.



	Fourth quarter
	2013
Production (MMBOE)	2.5 - 2.7
Crude oil % of production	57%
Price Realizations (pre-hedge, two-stream basis, % of NYMEX):
Crude oil	90% - 95%
Natural gas, including natural gas liquids	135% - 145%
Operating Costs & Expenses:
Lease operating expenses ($/BOE)	$8.25 - $8.75
Production taxes and ad valorem taxes (% of oil and gas revenue)	7.25%
General and administrative expenses ($/BOE)	$9.50 - $10.00
Depreciation, depletion and amortization ($/BOE)	$22.00 - $22.50

Conference Call Details

Laredo has scheduled a conference call today at 9:00 a.m. CT (10:00 a.m. ET) to discuss its third-quarter 2013 financial and operating results and management’s outlook for the future. Participants may listen to the call via the Company’s website at www.laredopetro.com, under the tab for “Investor Relations”. The conference call may also be accessed by dialing 1-877-415-3182, using the conference code 97144595. International participants may access the call by dialing 1-857-244-7325, also using conference code 97144595. It is recommended that participants dial in approximately 10 minutes prior to the start of the conference call. A telephonic replay will be available approximately two hours after the call on November 7, 2013 through Thursday, November 14, 2013. Participants may access this replay by dialing 1-888-286-8010, using conference code 65435182.

About Laredo

Laredo Petroleum Holdings, Inc. is an independent energy company with headquarters in Tulsa, Oklahoma. Laredo's business strategy is focused on the exploration, development and acquisition of oil and natural gas properties primarily in the Permian region of the United States.

Additional information about Laredo may be found on its website at www.laredopetro.com.

Forward-Looking Statements

This press release contains forward-looking statements as defined under Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, that address activities that Laredo assumes, plans, expects, believes, intends, projects, estimates or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. The forward-looking statements are based on management's current belief, based on currently available information, as to the outcome and timing of future events.

General risks relating to Laredo include, but are not limited to the risks described in its Annual Report on Form 10-K for the year ended December 31, 2012, Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, and those set forth from time to time in other filings with the Securities and Exchange Commission (“SEC”). These documents are available through Laredo’s website at www.laredopetro.com under the tab “Investor Relations” or through the SEC’s Electronic Data Gathering and Analysis Retrieval System ("EDGAR") at www.sec.gov. Any of these factors could cause Laredo's actual results and plans to differ materially from those in the forward-looking statements. Therefore, Laredo can give no assurance that its future results will be as estimated. Laredo does not intend to, and disclaims any obligation to, update or revise any forward-looking statement.

The SEC generally permits oil and gas companies, in filings made with the SEC, to disclose proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions and certain probable and possible reserves that meet the SEC’s definitions for such terms. In this communication, the Company may use the term “resource potential” which the SEC guidelines restrict from being included in filings with the SEC without strict compliance with SEC definitions. “Resource potential” refers to the Company’s internal estimates of unbooked hydrocarbon quantities that may be potentially added to proved reserves, largely from a specified resource play. A resource play is a term used by the Company to describe an accumulation of hydrocarbons known to exist over a large areal expanse and/or thick vertical section, which, when compared to a conventional play, typically has a lower geological and/or commercial development risk. Unbooked resource potential does not constitute reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or SEC rules and does not include any proved reserves. Actual quantities that may be ultimately recovered from the Company’s interests will differ substantially. Factors affecting ultimate recovery include the scope of the Company’s ongoing drilling program, which will be directly affected by the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors; and actual drilling results, including geological and mechanical factors affecting recovery rates. Estimates of unproved reserves may change significantly as development of the Company’s core assets provides additional data. In addition, the Company’s production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases.

Laredo Petroleum Holdings, Inc.

Condensed consolidated statements of operations



	Three months ended September 30,						Nine months ended September 30,
(in thousands, except per share data)	2013			2012			2013			2012
	(unaudited)						(unaudited)
Revenues:
Oil and natural gas sales	$	170,840		$	143,760		$	511,513		$	432,320
Natural gas transportation and treating	—			75			328			242
Total revenues	170,840			143,835			511,841			432,562
Costs and expenses:
Lease operating expenses	19,565			16,565			64,192			47,209
Production and ad valorem taxes	11,723			12,092			32,890			28,329
General and administrative	18,529			11,454			50,978			38,560
Stock-based compensation	5,876			2,767			13,556			7,602
Depreciation, depletion and amortization	55,982			63,266			186,719			174,238
Other	1,745			485			4,167			2,584
Total costs and expenses	113,420			106,629			352,502			298,522
Operating income	57,420			37,206			159,339			134,040
Non-operating income (expense):
Total gain (loss) on derivative financial instruments:
Commodity derivative financial instruments, net	(9,830		)	(24,070		)	(2,709		)	5,067
Interest rate derivatives, net	(8		)	(86		)	(23		)	(409		)
Income (loss) from equity method investee	48			—			(65		)	—
Interest expense	(24,929		)	(24,423		)	(76,221		)	(60,781		)
Interest and other income	59			13			86			44
Write-off of deferred loan costs	(1,502		)	—			(1,502		)	—
Gain (loss) on disposal of assets, net	607			(1		)	548			(9		)
Non-operating income (expense), net	(35,555		)	(48,567		)	(79,886		)	(56,088		)
Income (loss) from continuing operations before income taxes	21,865			(11,361		)	79,453			77,952
Income tax (expense) benefit:
Deferred income tax (expense) benefit	(10,048		)	4,090			(31,205		)	(28,063		)
Income (loss) from continuing operations	11,817			(7,271		)	48,248			49,889
Income (loss) from discontinued operations, net of tax	726			(113		)	1,516			(63		)
Net income (loss)	$	12,543		$	(7,384	)	$	49,764		$	49,826

Income (loss) from continuing operations per common share:
Basic	$	0.09		$	(0.06	)	$	0.37		$	0.39
Diluted	$	0.09		$	(0.06	)	$	0.37		$	0.39
Income (loss) from discontinued operations, per common share:
Basic	$	—		$	—		$	0.01		$	—
Diluted	$	—		$	—		$	0.01		$	—
Weighted average common shares outstanding:
Basic	134,461			127,001			129,701			126,909
Diluted	136,460			127,001			131,589			128,148

Laredo Petroleum Holdings, Inc.

Condensed consolidated balance sheets



(in thousands)	September 30, 2013		December 31, 2012
	(unaudited)
Assets:
Current assets	$	352,847	$	137,437
Net property and equipment	2,056,369		2,113,891
Other noncurrent assets	70,945		86,976
Total assets	$	2,480,161	$	2,338,304

Liabilities and stockholders' equity:
Current liabilities	$	207,800	$	262,068
Long-term debt	1,051,595		1,216,760
Other noncurrent liabilities	25,414		27,753
Stockholders' equity	1,195,352		831,723
Total liabilities and stockholders' equity	$	2,480,161	$	2,338,304

Laredo Petroleum Holdings, Inc.

Condensed consolidated statements of cash flows



	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2013			2012			2013			2012
	(unaudited)						(unaudited)
Cash flows from operating activities:
Net income (loss)	$	12,543		$	(7,384	)	$	49,764		$	49,826
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Deferred income tax expense (benefit)	10,369			(4,154		)	31,970			28,027
Depreciation, depletion and amortization	55,982			63,925			187,346			176,145
Bad debt expense	653			—			653			—
Non-cash stock-based compensation	5,876			2,767			13,556			7,602
Accretion of asset retirement obligations	350			315			1,154			871
Mark-to-market on derivatives:
Total (gain) loss on derivative financial instruments, net	9,838			386			2,732			(4,658		)
Cash settlements of matured derivative financial instruments, net	(4,069		)	30,764			588			18,879
Cash settlements received for early terminations of derivative financial instruments, net	5,366			—			5,366			—
Change in net present value of deferred premiums for derivative financial instruments	102			176			384			495
Cash premiums paid for derivative financial instruments	(2,671		)	(1,595		)	(7,920		)	(4,522		)
Amortization of deferred loan costs	1,278			1,265			3,905			3,533
Write-off of deferred loan costs	1,502			—			1,502			—
Other	(736		)	(45		)	(662		)	(126		)
Cash flow from operations before changes in working capital	96,383			86,420			290,338			276,072
Changes in working capital	(2,178		)	(3,171		)	(20,420		)	5,851
Changes in other noncurrent liabilities and fair value of performance unit awards	2,943			418			5,520			1,534
Net cash provided by operating activities	97,148			83,667			275,438			283,457
Cash flows from investing activities:
Acquisitions	(33,710		)	(20,496		)	(33,710		)	(20,496		)
Investment in equity method investee	—			—			(3,287		)	—
Oil and natural gas properties	(162,494		)	(225,296		)	(538,395		)	(699,142		)
Pipeline and gas gathering assets	(7,092		)	(4,062		)	(15,394		)	(11,093		)
Other fixed assets	(5,071		)	(1,181		)	(13,874		)	(6,169		)
Proceeds from dispositions of capital assets, net of costs	429,702			—			429,702			34
Net cash provided by (used in) investing activities	221,335			(251,035		)	(174,958		)	(736,866		)
Cash flows from financing activities:
Borrowings on senior secured credit facility	—			50,000			230,000			245,000
Payments on senior secured credit facility	(395,000		)	—			(395,000		)	(280,000		)
Issuance of 2022 Notes	—			—			—			500,000
Proceeds from issuance of common stock, net of offering costs	298,104			—			298,104			—
Purchase of treasury stock	(559		)	—			(1,478		)	—
Proceeds from exercise of employee stock options	654			—			654			—
Payments for loan costs	—			—			(714		)	(10,476		)
Net cash (used in) provided by financing activities	(96,801		)	50,000			131,566			454,524
Net increase (decrease) in cash and cash equivalents	221,682			(117,368		)	232,046			1,115
Cash and cash equivalents, beginning of period	43,588			146,485			33,224			28,002
Cash and cash equivalents, end of period	$	265,270		$	29,117		$	265,270		$	29,117

Laredo Petroleum Holdings, Inc.

Selected operating data

(Unaudited)



	Three months ended September 30,						Nine months ended September 30,
	2013			2012			2013			2012
Production data:
Oil (MBbl)	1,282			1,194			4,127			3,425
Natural gas (MMcf)	7,965			9,859			29,025			28,893
Oil equivalents⁽¹⁾⁽²⁾ (MBOE)	2,609			2,837			8,964			8,240
Average daily production⁽²⁾ (BOE/d)	28,361			30,835			32,836			30,075
% Oil and condensate	49		%	42		%	46		%	42		%

Average sales prices:
Oil, realized⁽³⁾($/Bbl)	$	100.62		$	86.41		$	90.30		$	89.54
Natural gas, realized⁽³⁾($/Mcf)	5.26			4.12			4.79			4.35
Average price, realized⁽³⁾ ($/BOE)	65.48			50.68			57.08			52.47
Oil, hedged⁽⁴⁾ ($/Bbl)	94.63			85.42			88.05			87.80
Natural gas, hedged⁽⁴⁾ ($/Mcf)	5.35			4.72			4.84			5.04
Average price, hedged⁽⁴⁾ ($/BOE)	62.82			52.35			56.21			54.16

Average costs per BOE:
Lease operating expenses	$	7.50		$	5.84		$	7.16		$	5.73
Production and ad valorem taxes	4.49			4.26			3.67			3.44
General and administrative⁽⁵⁾	9.35			5.01			7.20			5.60
Depreciation, depletion and amortization	21.46			22.30			20.83			21.15
Total	$	42.80		$	37.41		$	38.86		$	35.92

_______________________________________________________________________________


(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 in the table above.


(3)	Realized crude oil and natural gas prices are the actual prices realized at the wellhead after all adjustments for NGL content, quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price at the wellhead.

(4)

Hedged prices reflect the after effect of commodity hedging transactions on average sales prices. The calculation of such after effects include current period settlements of matured derivative instruments in accordance with the applicable generally accepted accounting principles in the United States of America and an adjustment to reflect premiums incurred previously or upon settlement that are attributable to instruments 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.

(5)

General and administrative includes non-cash stock-based compensation of $5.9 million and $2.8 million for the three months ended September 30, 2013 and 2012, respectively, and $13.6 million and $7.6 million for the nine months ended September 30, 2013 and 2012, respectively. Excluding stock-based compensation from the above metric results in general and administrative cost per BOE of $7.10 and $4.04 for the three months ended September 30, 2013 and 2012, respectively, and $5.69 and $4.68 for the nine months ended September 30, 2013 and 2012, respectively.

Laredo Petroleum Holdings, Inc.

Costs incurred

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



	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2013		2012		2013		2012
	(unaudited)				(unaudited)
Property acquisition costs:
Proved	$	9,652	$	16,925	$	9,652	$	16,925
Unproved	27,087		3,693		27,087		3,693
Exploration	8,317		13,911		29,245		65,597
Development costs⁽¹⁾	148,877		215,227		471,609		642,826
Total costs incurred	$	193,933	$	249,756	$	537,593	$	729,041

_______________________________________________________________________________


(1)	The costs incurred for oil and natural gas development activities include $0.7 million and $1.1 million in asset retirement obligations for the three months ended September 30, 2013 and 2012, respectively, and $2.0 million and $3.4 million for the nine months ended September 30, 2013 and 2012, respectively.

Laredo Petroleum Holdings, Inc.

Supplemental reconciliation of GAAP to non-GAAP financial measure

(Unaudited)

Adjusted net income

Adjusted net income is a performance measure used by the Company to evaluate performance, prior to impairment of long-lived assets, total gains or losses on derivative financial instruments, cash settlements of matured commodity derivative financial instruments, cash settlements on early terminated derivative financial instruments, gains or losses on sale of assets, write-off of deferred loan costs and bad debt expense.

The following presents a reconciliation of net income (loss) to adjusted net income:



	Three months ended September 30,						Nine months ended September 30,
(in thousands, except for per share data)	2013			2012			2013			2012
Net income (loss)	$	12,543		$	(7,384	)	$	49,764		$	49,826
Plus:
Total (gain) loss on derivative financial instruments, net	9,838			24,156			2,732			(4,658		)
Cash settlements of matured commodity derivative financial instruments, net	(3,975		)	7,078			888			20,901
Cash settlements received for early terminations of derivative financial instruments, net	5,366			—			5,366			—
(Gain) loss on disposal of assets, net	(607		)	1			(548		)	9
Write-off of deferred loan costs	1,502			—			1,502			—
Bad debt expense	653			—			653			—
	25,320			23,851			60,357			66,078
Income tax adjustment⁽¹⁾	(4,600		)	(11,245		)	(3,813		)	(5,851		)
Adjusted net income	$	20,720		$	12,606		$	56,544		$	60,227

Adjusted net income per common share:
Basic	$	0.15		$	0.10		$	0.44		$	0.47
Diluted	$	0.15		$	0.10		$	0.43		$	0.47
Weighted average common shares outstanding:
Basic	134,461			127,001			129,701			126,909
Diluted	136,460			127,001			131,589			128,148

_______________________________________________________________________________


(1)	The income tax adjustment for the three and nine months ended September 30, 2013 and 2012 is calculated by applying the estimated annual effective tax rate of 36% without regards to discrete items.

Non-GAAP financial measures and reconciliations

Adjusted EBITDA is a non-GAAP financial measure that the Company defines as net income or loss plus adjustments for interest expense, depreciation, depletion and amortization, impairment of long-lived assets, write-off of deferred loan costs, bad debt expense, gains or losses on sale of assets, total gains or losses on derivative financial instruments, cash settlements of matured commodity derivative financial instruments, cash settlements on early terminated derivative financial instruments, premiums paid for derivative financial instruments 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, the Company believes Adjusted EBITDA is useful to an investor in evaluating it's 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 and 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 the Company's operations from period to period by removing the effect of it's capital structure from it's operating structure; and


•	is used by the Company for various purposes, including as a measure of operating performance, in presentations to the Board, 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 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. The measurements of Adjusted EBITDA for financial reporting as compared to compliance under the debt agreements differ.

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



	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2013			2012			2013			2012
Net income (loss)	$	12,543		$	(7,384	)	$	49,764		$	49,826
Plus:
Interest expense	24,929			24,423			76,221			60,781
Depreciation, depletion and amortization	66,234			63,925			187,346			176,145
Write-off of deferred loan costs	1,502			—			1,502			—
Bad debt expense	653			—			653			—
(Gain) loss on disposal of assets, net	(607		)	1			(548		)	9
Total (gain) loss on derivative financial instruments, net	9,838			24,156			2,732			(4,658		)
Cash settlements of matured commodity derivative financial instruments, net	(3,975		)	7,078			888			20,901
Cash settlements received for early terminations of derivative financial instruments, net	5,366			—			5,366			—
Premiums paid for derivative financial instruments that matured during the period(1)	(2,925		)	(2,349		)	(8,681		)	(6,786		)
Non-cash stock-based compensation	5,876			2,767			13,556			7,602
Income tax expense (benefit)	20,338			(4,154		)	31,970			28,027
Adjusted EBITDA	$	139,772		$	108,463		$	360,769		$	331,847

_______________________________________________________________________________

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

# # #

Contact:

Ron Hagood: (918) 858-5504 - RHagood@laredopetro.com

13-17

Laredo Petroleum, Inc. - FORM 8-K - EX-99.1 - EXHIBIT - November 7, 2013

Attached files

Laredo Petroleum, Inc. Reports