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

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8-K - 8-K - Laredo Petroleum, Inc.	a201402278kerpr.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 Announces 2013 Fourth-Quarter and Full-Year

Financial and Operating Results

TULSA, OK - February 27, 2014 - Laredo Petroleum, Inc. (NYSE: LPI) (“Laredo” or “the Company”), today announced its 2013 fourth-quarter and full-year results. For the fourth quarter of 2013, the Company reported net income attributable to common stockholders of $68.2 million, or $0.48 per diluted share. Adjusted Net Income, a non-GAAP financial measure, for the fourth quarter of 2013 was $19.1 million, or $0.13 per diluted share. Adjusted EBITDA, a non-GAAP financial measure, for the fourth quarter of 2013 was $111.4 million. For the year ended December 31, 2013, the Company reported net income attributable to common stockholders of $118.0 million, or $0.88 per diluted share, Adjusted Net Income of $75.7 million, or $0.56 per diluted share, and Adjusted EBITDA of $472.2 million. (Please see supplemental financial information at the end of this news release for reconciliations of these non-GAAP financial measures.)

2013 Full-Year Highlights


•	Increased Permian production volumes in 2013 to 24,960 barrels of oil equivalent per day (“BOE/D”) on a two-stream basis, up approximately 21% from 2012, in spite of significant operational disruptions due to severe winter weather in the fourth quarter of 2013


•	Increased Adjusted EBITDA in 2013 to a record $472.2 million


•	Increased cash margin per barrel of oil equivalent (“BOE”) to $49.67 per BOE in fourth-quarter 2013, up approximately 40% from fourth-quarter 2012


•	Increased Permian proved reserves to 203.6 million BOE in 2013 on a two-stream basis, up approximately 27% from year-end 2012


•	Replaced approximately 487% of total production at a finding and development cost of $12.00/BOE


•	Divested the Company’s Anadarko Basin properties for proceeds of approximately $428 million, net of working capital adjustments, becoming a pure-play Permian Basin producer


•	Strengthened the balance sheet and reduced the ratio of debt less cash to Adjusted EBITDA to 1.8 at year end


•	Increased liquidity to more than $1 billion at year end

“During 2013, Laredo continued to implement its multi-year plan for the Company’s world-class Permian acreage and made significant progress in positioning the Company for the multi-zone development program that we are executing in 2014,” commented Randy A. Foutch, Laredo Chairman and Chief Executive Officer.

“We maintained our disciplined, data-driven approach to developing our Permian-Garden City asset by confirming both the vertical and horizontal spacing of laterals and are continuing to gather and process the data needed to further optimize the drilling and completion of horizontal wells. Additionally, we accelerated our build-out of production corridors to efficiently move oil, gas and water both on and off leases. In 2014, we expect to invest approximately 85% of our drilling and completion budget on development drilling and will continue to optimize our development program. Our focus on multi-well pad drilling is expected to further reduce drilling and completion costs while maintaining our strong well results and continuing to enhance our already impressive economics. With the sale of our Anadarko Basin assets, subsequent capital raises and increased, high-quality reserves to underpin our credit facility, we believe we are well positioned to fund our accelerating multi-zone development program and bring forward the value of the Permian-Garden City asset for our stockholders.”

Operational Update

Laredo began completing long lateral horizontal wells (i.e., longer than 6,000 feet) in the Permian Basin in mid-2012 and currently has drilled and completed 32 wells with at least 180 days of production history and 23 wells with one year of production history. The performance of these wells over an extended time frame continues to support the Company’s type curves by zone. Average results from the three Wolfcamp zones are exceeding the Company’s respective type curves. The Cline wells are currently below the Company’s type curve for that zone. However, the last two completions in the Cline are both performing at more than 125% of the type curve through 180 days of production history.



	Wells with 180 days of Production			Wells with 365 days of Production
Zone	No. of Wells	Avg. Cumulative Production per Well	% of Type Curve	No. of Wells	Avg. Cumulative Production per Well	% of Type Curve
	(long laterals)	(Two-stream MBOE)		(long laterals)	(Two-Stream MBOE)
Upper Wolfcamp	21	87.3	104%	15	132.0	102%
Middle Wolfcamp	2	103.9	143%	2	150.4	135%
Lower Wolfcamp	4	82.4	111%	2	120.9	105%
Cline	5	71.3	92%	4	97.0	84%

During the fourth quarter, Laredo continued the successful implementation of the Company’s multi-zone development strategy, completing horizontal wells in the Upper, Middle and Lower Wolfcamp zones. The Company completed 21 vertical wells and 15 horizontal wells during the fourth quarter that have now reached the peak 24-hour initial production (“IP”) rate and achieved 30 days of production history. The impact of the severe winter storms that hit the Midland Basin during the fourth quarter of 2013 had a negative affect on the average 30-day IP rates for these wells due to power interruptions, compressor performance and lack of truck availability. However, the Company does not believe that there was any long-term impact to the performance of these wells. The horizontal results are detailed as follows:



	Lateral	No. of Frac	Completion
Well Name	Length	Stages	Date	Peak 24-Hr IP	Avg. 30-Day IP
	(feet)			Two-stream (BOE/D)
Upper Wolfcamp
Barbee C/B 1-2HU (a)	7,465	27	Oct-13	980	736
Sugg A 171-1HU (b)	7,002	25	Oct-13	829	627
JE Cox #3308-HU (c)	7,550	26	Oct-13	1,193	498
Sugg A 158-3HU (d)	7,440	26	Nov-13	942	500
JE Cox B Yellow Rose 40 #3309-HU (c)	7,529	27	Nov-13	866	620
Sugg E Sugg A SL 208-5HU (e)	7,121	26	Dec-13	707	557
Middle Wolfcamp
Barbee C/B/D 1-2HM (a)	7,384	26	Oct-13	812	549
Sugg A 171-2HM (b)	6,053	21	Oct-13	711	539
Book Sugg C 190-2HM	8,371	31	Nov-13	1,465	949
Book Sugg C 190-1HM	6,333	26	Nov-13	1,568	703
Sugg A 158-2HM (d)	7,493	24	Nov-13	778	610
Glass 214 - Glass 219-1HM	7,137	25	Dec-13	187	82
Sugg E Sugg A 208-4HM (e)	6,732	26	Dec-13	1,469	897
Lower Wolfcamp
Sugg A 171-3HL (b)	7,402	25	Oct-13	1,843	691
Bodine C 30-3HL	6,975	25	Nov-13	1,221	674

(a), (b), (c), (d), (e) Letter groupings designate respective wells drilled on a common pad

Eleven of the 15 horizontal wells completed in the fourth quarter were drilled on multi-well pads in two-stacked, three-stacked or offset pad configurations. Seven of the wells were completed in the Middle Wolfcamp zone, more than doubling the total number of horizontal wells the Company has completed in that zone. The average performance of six of these Middle Wolfcamp wells is currently greater than the results anticipated by the Company’s 650,000 BOE type curve (two-stream) for the Middle Wolfcamp. The seventh Middle Wolfcamp well, the Glass 214 - Glass 219-1HM, was drilled in northern Glasscock County across the facies change that we had previously identified. The results of this well are disappointing but are still being evaluated. The Company’s six wells completed in the Upper Wolfcamp and two wells completed in the Lower Wolfcamp are, on average, performing as expected relative to their respective type curves.

The Company exited 2013 operating five horizontal rigs and six vertical rigs on its Permian-Garden City acreage. A sixth horizontal rig was recently delivered and a seventh horizontal rig is anticipated to begin drilling this quarter. The six horizontal rigs will be drilling on multi-well pads in two-, three- and four-stacked configurations, with the majority of these wells expected to impact production late in the second quarter of 2014. The cost benefits of drilling multi-well pads in development mode have reduced 2014 budgeted well costs below 2013 average well costs and are expected to result in cost savings of 10-15% per well from the 2013 average well costs by year-end 2014.

In the fourth quarter of 2013, Laredo’s average daily production from the Permian Basin, which includes one well in the Dalhart Basin, of 24,976 BOE/D reflects the impact of the severe winter storm which restricted production, drilling and completion operations for approximately two weeks during the quarter. Average realized prices in the fourth quarter of 2013 increased to $68.24 per BOE from $49.42 per BOE in the prior-

year quarter, reflecting the increase in oil production as a percentage of total production and the Company’s initial quarter as a pure-play Permian Basin producer. In the fourth quarter of 2013, the Company’s cash margin (i.e., average realized price less unit lease operating expense, production taxes and the cash portion of general and administrative expense) increased to $49.67 per BOE from $35.40 per BOE in the fourth quarter of 2012. The approximate 40% increase in cash margin was primarily the result of the Company’s increased oil production as a percentage of total production coupled with higher average realized prices for oil and natural gas.

Reserves

In 2013, Laredo increased proved reserves approximately 8% from year-end 2012 to a record 203.6 million BOE, even after the sale of 28.6 million BOE associated with the Anadarko Basin. On a stand-alone basis, Permian reserves increased approximately 27% from year-end 2012. The drill bit reserve growth in 2013 was accomplished at a finding and development cost of $12.00 per BOE and replaced approximately 487% of total production. Year-end 2013 reserves were comprised of 55% oil, 35% proved developed and had a pre-tax present value (“PV-10”) of approximately $3.1 billion.

2013 Capital Program

During the fourth quarter of 2013, Laredo invested approximately $202.4 million in total capital expenditures, with approximately $182.8 million allocated to development activities. For the full year of 2013, the Company invested approximately $740.0 million in total capital expenditures, with approximately $654.5 million dedicated to development activities and approximately $36.7 in bolt-on acquisitions to the Permian-Garden City asset.

2014 Capital Program

In 2014, Laredo expects to invest approximately $1 billion in total capital expenditures, excluding acquisitions. Approximately $800 million is expected to be directed to drilling and completion activities including approximately 75 gross operated horizontal wells and 125 gross operated vertical wells. Additionally, $130 million will be allocated to facilities, including the initial build-out of production corridors that will support efficient, multi-well pad development for many years. The responsibilities of Laredo Midstream Services, LLC, have been expanded to encompass the building of the production facilities and the management of the water resources necessary to produce oil and gas. The remaining $70 million is expected to be invested in non-operated wells, land and seismic.

Liquidity

At December 31, 2013, the Company had approximately $198 million in cash and equivalents and an undrawn senior secured credit facility, which had $825 million available for borrowings, resulting in total liquidity of more than $1 billion. On January 23, 2014, the Company received net proceeds of approximately $442 million from a senior unsecured notes offering and as a result, the amount available for borrowings under the senior secured credit facility was reset to $812.5 million. Total liquidity is currently more than $1.4 billion.

Commodity Derivatives

Laredo maintains an active hedging program to underpin the Company’s capital program and reduce the variability in its anticipated cash flow due to fluctuations in commodity prices. At December 31, 2013, the Company had hedges in place for 2014 on 5,643,496 barrels of oil (“Bbl”) at a weighted average floor price of $87.97 per Bbl and 9,600,000 million British thermal units (“MMBtu”) of natural gas at a weighted average floor price of $3.00 per MMBtu. Subsequent to December 31, 2013, the Company entered into hedge contracts to sell 5,508,000 MMBtu of natural gas at $4.32 per MMBtu between March 2014 and December 2014. Additionally, in February 2014, the Company received net proceeds of approximately $77 million from the early termination of the Company’s four-year physical crude oil contract and corresponding oil basis swap between the Light Louisiana Sweet Argus index crude oil price and the Brent index crude oil price. The Company agreed to settle the contracts early due to the counterparty's decision to exit the physical commodity trading business.

2014 Guidance

The table below reflects the Company’s guidance for first-quarter and full-year 2014:



	First-quarter	Full-year
	2014	2014
Production (MMBOE)	2.3 - 2.5	12.2 - 12.7
Crude oil % of production	58%	58%
Price Realizations (pre-hedge, two-stream basis, % of NYMEX):
Crude oil	90% - 95%	90% - 95%
Natural gas, including natural gas liquids	135% - 145%	135% - 145%
Operating Costs & Expenses:
Lease operating expenses ($/BOE)	$8.00 - $8.50	$7.25 - $7.75
Production taxes (% of oil and gas revenue)	7.00%	7.00%
General and administrative expenses ($/BOE)	$11.50 - $12.00	$9.00 - $9.50
Depletion, depreciation and amortization ($/BOE)	$21.00 - $22.00	$21.50 - $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 fourth-quarter and full-year 2013 financial and operating results and management’s outlook for the future, the content of which is not part of this earnings release. 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 1-866-318-8613, using the conference code 10846493. International participants may access the call by dialing 1-617-399-5132, also using conference code 10846493. 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 February 27, 2014 through Thursday, March 6, 2014. Participants may access this replay by dialing 1-888-286-8010, using conference code 50798123.

About Laredo

Laredo Petroleum, 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 (and oral statements made regarding the subjects of this release, including on the conference call announced herein) 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, 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 the conference call, 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, Inc.

Condensed consolidated statements of operations



	Three months ended December 31,						Year ended December 31,
(in thousands, except per share data)	2013			2012			2013			2012
	(unaudited)						(unaudited)
Revenues:
Oil and natural gas sales	$	153,331		$	151,249		$	664,844		$	583,569
Transportation and treating	85			83			413			325
Total revenues	153,416			151,332			665,257			583,894
Costs and expenses:
Lease operating expenses	14,944			20,116			79,136			67,325
Production and ad valorem taxes	9,506			9,308			42,396			37,637
Transportation and treating	677			56			1,571			162
Drilling and production	569			845			2,688			2,452
General and administrative	17,285			13,490			68,263			52,050
Stock-based compensation	7,877			2,454			21,433			10,056
Accretion of asset retirement obligations	321			329			1,475			1,200
Depletion, depreciation and amortization	47,225			66,834			233,944			241,072
Total costs and expenses	98,404			113,432			450,906			411,954
Operating income	55,012			37,900			214,351			171,940
Non-operating income (expense):
Gain (loss) on derivatives:
Commodity derivatives, net	82,611			3,733			79,902			8,800
Interest rate derivatives, net	(1		)	(3		)	(24		)	(412		)
Income from equity method investee	94			—			29			—
Interest expense	(24,106		)	(24,791		)	(100,327		)	(85,572		)
Interest and other income	77			15			163			59
Write-off of deferred loan costs	—			—			(1,502		)	—
Loss on disposal of assets, net	(2,056		)	(42		)	(1,508		)	(51		)
Non-operating income (expense), net	56,619			(21,088		)	(23,267		)	(77,176		)
Income from continuing operations before income taxes	111,631			16,812			191,084			94,764
Income tax expense:
Deferred	(43,302		)	(4,940		)	(74,507		)	(33,003		)
Total income tax expense	(43,302		)	(4,940		)	(74,507		)	(33,003		)
Income from continuing operations	68,329			11,872			116,577			61,761
Income (loss) from discontinued operations, net of tax	(93		)	(44		)	1,423			(107		)
Net income	$	68,236		$	11,828		$	118,000		$	61,654
Net income per common share:
Basic:
Income from continuing operations	$	0.48		$	0.09		$	0.88		$	0.49
Income (loss) from discontinued operations, net of tax	—			—			0.01			—
Net income per share	$	0.48		$	0.09		$	0.89		$	0.49
Diluted:
Income from continuing operations	$	0.48		$	0.09		$	0.87		$	0.48
Income (loss) from discontinued operations, net of tax	—			—			0.01			—
Net income per share	$	0.48		$	0.09		$	0.88		$	0.48
Weighted average common shares outstanding:
Basic	140,766			127,100			132,490			126,957
Diluted	142,779			128,248			134,378			128,171

Laredo Petroleum, Inc.

Condensed consolidated balance sheets



(in thousands)	December 31, 2013		December 31, 2012
Assets:	(unaudited)		(unaudited)
Current assets	$	307,609	$	137,437
Net property and equipment	2,204,324		2,113,891
Other noncurrent assets	111,827		86,976
Total assets	$	2,623,760	$	2,338,304

Liabilities and stockholders' equity:
Current liabilities	$	253,969	$	262,068
Long-term debt	1,051,538		1,216,760
Other noncurrent liabilities	45,997		27,753
Stockholders' equity	1,272,256		831,723
Total liabilities and stockholders' equity	$	2,623,760	$	2,338,304

Laredo Petroleum, Inc.

Condensed consolidated statements of cash flows



	Three months ended December 31,						Year ended December 31,
(in thousands)	2013			2012			2013			2012
	(unaudited)						(unaudited)
Cash flows from operating activities:
Net income	$	68,236		$	11,828		$	118,000		$	61,654
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred income tax expense	43,318			4,922			75,288			32,949
Depletion, depreciation and amortization	47,225			67,504			234,571			243,649
Bad debt expense	—			—			653			—
Non-cash stock-based compensation	7,877			2,454			21,433			10,056
Accretion of asset retirement obligations	321			329			1,475			1,200
Mark-to-market on derivatives:
Total gain on derivatives, net	(82,610		)	(3,730		)	(79,878		)	(8,388		)
Cash settlements of matured derivatives, net	3,157			6,031			3,745			24,910
Cash settlements received for early terminations of derivatives, net	642			—			6,008			—
Change in net present value of deferred premiums for derivatives	78			173			462			668
Cash premiums paid for derivatives	(2,357		)	(1,596		)	(10,277		)	(6,118		)
Amortization of deferred loan costs	1,118			1,283			5,023			4,816
Write-off of deferred loan costs	—			—			1,502			—
Other	(169		)	(5		)	(831		)	(131		)
Cash flow from operations before changes in working capital	86,836			89,193			377,174			365,265
Changes in working capital	2,743			3,765			(17,677		)	9,616
Changes in other noncurrent liabilities and fair value of performance unit awards	(288		)	361			5,232			1,895
Net cash provided by operating activities	89,291			93,319			364,729			376,776
Cash flows from investing activities:
Acquisitions	—			—			(33,710		)	(20,496		)
Investment in equity method investee	—			—			(3,287		)	—
Oil and natural properties	(163,954		)	(196,170		)	(702,349		)	(895,312		)
Pipeline and gathering assets	(9,015		)	(5,148		)	(24,409		)	(16,241		)
Other fixed assets	(2,383		)	(2,586		)	(16,257		)	(8,755		)
Proceeds from dispositions of capital assets, net of costs	20,426			19			450,128			53
Net cash used in investing activities	(154,926		)	(203,885		)	(329,884		)	(940,751		)
Cash flows from financing activities:
Borrowings on senior secured credit facility	—			115,000			230,000			360,000
Payments on senior secured credit facility	—			—			(395,000		)	(280,000		)
Issuance of 2022 Notes	—			—			—			500,000
Proceeds from issuance of common stock, net of offering costs	—			—			298,104			—
Proceeds from exercise of employee stock options	1,396			—			2,050			—
Purchase of treasury stock	(605		)	—			(2,083		)	—
Payments for loan costs	(2,273		)	(327		)	(2,987		)	(10,803		)
Net cash (used in) provided by financing activities	(1,482		)	114,673			130,084			569,197
Net (decrease) increase in cash and cash equivalents	(67,117		)	4,107			164,929			5,222
Cash and cash equivalents, beginning of period	265,270			29,117			33,224			28,002
Cash and cash equivalents, end of period	$	198,153		$	33,224		$	198,153		$	33,224

Laredo Petroleum, Inc.

Selected operating data

(Unaudited)



	Three months ended December 31,						Year ended December 31,
	2013			2012			2013			2012
Production data:
Oil (MBbl)	1,360			1,350			5,487			4,775
Natural gas (MMcf)	5,323			10,255			34,348			39,148
Oil equivalents (MBOE)⁽¹⁾⁽²⁾	2,247			3,060			11,211			11,300
Average daily production (BOE/D)⁽²⁾	24,426			33,261			30,716			30,874
% Oil	61		%	44		%	49		%	42		%

Average sales prices:
Oil, realized($/Bbl)⁽³⁾	$	89.74		$	80.16		$	90.16		$	86.89
Natural gas, realized($/Mcf)⁽³⁾	5.88			4.19			4.95			4.31
Average price, realized ($/BOE)⁽³⁾	68.24			49.42			59.29			51.65
Oil, hedged ($/Bbl)⁽⁴⁾	90.58			79.98			88.68			85.59
Natural gas, hedged ($/Mcf)⁽⁴⁾	5.77			4.59			4.98			4.92
Average price, hedged ($/BOE)⁽⁴⁾	68.49			50.69			58.66			53.22

Average costs per BOE:
Lease operating expenses	$	6.65		$	6.57		$	7.06		$	5.96
Production and ad valorem taxes	4.23			3.04			3.78			3.33
General and administrative⁽⁵⁾	11.20			5.21			8.00			5.50
Depletion, depreciation and amortization	21.02			21.84			20.87			21.33
Total	$	43.10		$	36.66		$	39.71		$	36.12

_______________________________________________________________________________


(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 natural gas liquids 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 $7.9 million and $2.5 million for the three months ended December 31, 2013 and 2012, respectively, and $21.4 million and $10.1 million for the year ended December 31, 2013 and 2012, respectively. Excluding stock-based compensation from the above metric results in general and administrative cost per BOE of $7.69 and $4.41 for the three months ended December 31, 2013 and 2012, respectively, and $6.09 and $4.61 for the year ended December 31, 2013 and 2012, respectively.

Laredo Petroleum, Inc.

Costs incurred

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



	Three months ended December 31,				Year ended December 31,
(in thousands, unaudited)	2013		2012		2013		2012
	(unaudited)				(unaudited)
Property acquisition costs:
Proved	$	—	$	—	$	9,652	$	16,925
Unproved	—		—		27,087		3,693
Exploration	19,518		27,669		48,763		93,266
Development costs⁽¹⁾	182,843		196,292		654,452		839,118
Total costs incurred	$	202,361	$	223,961	$	739,954	$	953,002

_______________________________________________________________________________


(1)	The costs incurred for oil and natural gas development activities include $4.8 million and $4.0 million in asset retirement obligations for the three months ended December 31, 2013 and 2012, respectively, and $6.8 million and $7.4 million for the year ended December 31, 2013 and 2012, respectively.

Laredo Petroleum, 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 derivatives, cash settlements of matured commodity derivatives, cash settlements on early terminated derivatives, 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 to Adjusted Net Income:



	Three months ended December 31,						Year ended December 31,
(in thousands, except for per share data, unaudited)	2013			2012			2013			2012
Net income	$	68,236		$	11,828		$	118,000		$	61,654
Plus:
Total gain on derivatives, net	(82,610		)	(3,730		)	(79,878		)	(8,388		)
Cash settlements of matured commodity derivatives, net	3,158			6,124			4,046			27,025
Cash settlements received for early terminations of derivatives, net	642			—			6,008			—
Loss on disposal of assets, net	2,056			43			1,508			52
Write-off of deferred loan costs	—			—			1,502			—
Bad debt expense	—			—			653			—
	(8,518		)	14,265			51,839			80,343
Income tax adjustment⁽¹⁾	27,631			(853		)	23,818			(6,541		)
Adjusted net income	$	19,113		$	13,412		$	75,657		$	73,802

Adjusted net income per common share:
Basic	$	0.14		$	0.11		$	0.57		$	0.58
Diluted	$	0.13		$	0.10		$	0.56		$	0.58
Weighted average common shares outstanding:
Basic	140,766			127,100			132,490			126,957
Diluted	142,779			128,248			134,378			128,171

_______________________________________________________________________________


(1)	The income tax adjustment for the three and twelve months ended December 31, 2013 is calculated by applying the estimated annual effective tax rate of 36% without regard to discrete items. The income tax adjustment for the three and twelve months ended December 31, 2012 is calculated by applying the estimated annual effective tax rate of 35%.

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, total 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, 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 for continuing and discontinued operations to Adjusted EBITDA:



	Three months ended December 31,						Year ended December 31,
(in thousands, unaudited)	2013			2012			2013			2012
Net income	$	68,236		$	11,828		$	118,000		$	61,654
Plus:
Interest expense	24,106			24,791			100,327			85,572
Depletion, depreciation and amortization	47,225			67,504			234,571			243,649
Write-off of deferred loan costs	—			—			1,502			—
Bad debt expense	—			—			653			—
Loss on disposal of assets, net	2,056			43			1,508			52
Total gain on derivatives, net	(82,610		)	(3,730		)	(79,878		)	(8,388		)
Cash settlements of matured commodity derivatives, net	3,158			6,124			4,046			27,025
Cash settlements received for early terminations of derivatives, net	642			—			6,008			—
Premiums paid for derivatives that matured during the period⁽¹⁾	(2,611		)	(2,349		)	(11,292		)	(9,135		)
Non-cash stock-based compensation	7,877			2,454			21,433			10,056
Income tax expense	43,318			4,922			75,288			32,949
Adjusted EBITDA	$	111,397		$	111,587		$	472,166		$	443,434

_______________________________________________________________________________

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

Finding & Development Cost

Finding and development cost, or F&D cost, is calculated by dividing (x) development, exploitation, and exploration capital expenditures for the period, plus unevaluated capital expenditures as of the beginning of the period, less unevaluated capital expenditures as of the end of the period, by (y) reserve additions for the period, excluding acquired reserves. The methods we use to calculate our F&D cost may differ significantly from methods used by other companies to compute similar measures. As a result, our F&D cost may not be comparable to similar measures provided by other companies. We believe that providing the measure of F&D cost is useful in evaluating the costs, on a per barrel of oil equivalent basis, to add proved reserves.

However, this measure is provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with generally accepted accounting principles. Due to various factors, including timing differences in the addition of proved reserves and the related costs to develop those reserves, F&D cost do not necessarily reflect precisely the costs associated with particular reserves. As a result of various factors that could materially affect the timing and amounts of future increases in reserves and the timing and amounts of future costs, we cannot assure you that our future F&D cost will not differ materially from those presented.



Laredo Petroleum, Inc.
2013 F&D Cost
(Unaudited)
	F&D
($ in millions, except per unit amounts)
Exploration, development & exploitation capital	$	696.4
Acquisitions (if applicable)	—
Asset retirement obligation additions	6.8
Adjustments:
Unevaluated costs as of December 31, 2012	159.9
Unevaluated costs as of December 31, 2013	(208.1		)
Adjusted capital expenditures related to reserve additions	$	655.0

Reserve extensions, discoveries and revisions	54.6
Acquisitions (if applicable)	—
Total reserve additions	54.6

Cost per BOE	$	12.00

PV-10

PV-10 is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the standardized measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10 percent. We believe that the presentation of the PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas assets. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas assets. However, PV-10 is not a substitute for the standardized measure of discounted future net cash flows. Our PV-10 measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of our oil and natural gas reserves.



Laredo Petroleum, Inc.
Reconciliation of Pre-tax PV-10 Non-GAAP Financial Measure
(Unaudited)
($ in millions)	December 31, 2013
Pre-tax PV-10	$	3,053.3
Present value of future income taxes discounted at 10%	(731.1		)
Standardized measure of discounted future net cash flows	$	2,322.2

# # #

Contacts:

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

14-6

Laredo Petroleum, Inc. - FORM 8-K - EX-99.1 - EXHIBIT - February 27, 2014

Attached files

Laredo Petroleum, Inc. Reports