10-Q 1 a3q1410q.htm 10-Q 3Q14 Laredo Petroleum, Inc.
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 September 30, 2014
 or
 o         TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the transition period from                             to                            
Commission File Number: 001-35380
 Laredo Petroleum, Inc.
(Exact Name of Registrant as Specified in Its Charter)
Delaware
 (State or Other Jurisdiction of
Incorporation or Organization)
 
45-3007926
 (I.R.S. Employer
Identification No.)
15 W. Sixth Street, Suite 900
 
 
Tulsa, Oklahoma
 
74119
(Address of Principal Executive Offices)
 
(Zip code)
(918) 513-4570
(Registrant’s Telephone Number, Including Area Code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý  No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý  No o
     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. 
Large accelerated filer ý
 
Accelerated filer o
 
 
 
Non-accelerated filer o
 
Smaller reporting company o
(Do not check if a smaller reporting company)
 
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o  No ý 
Number of shares of registrant’s common stock outstanding as of November 3, 2014: 143,685,200


TABLE OF CONTENTS 
 
 
Page
 
Part I
 
Item 1.
 
 
 
 
 
Item 2.
Item 3.
Item 4.
 
Part II
 
Item 1.
Item 1A.
Item 2.
Item 3.
Item 4.
Item 5.
Item 6.
 

ii

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
Various statements contained in or incorporated by reference into this Quarterly Report on Form 10-Q (this "Quarterly Report") are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. 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:
•
volatility of oil and natural gas prices;
•
changes in domestic and global demand for oil and natural gas;
•
the continuation of restrictions on the export of domestic oil and its potential to cause weakness in domestic pricing;
•
the possible introduction of regulations that prohibit or restrict our ability to apply hydraulic fracturing to our oil and natural gas wells and to access and dispose of water used in these operations;
•
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;
•
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

iii

considered in light of various factors, including those set forth under "Part I, Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations", "Part II, Item 1A. Risk Factors" and elsewhere in this Quarterly Report, under "Part I, Item 1A. Risk Factors" and "Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations" in our Annual Report on Form 10-K for the fiscal year ended December 31, 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.

iv


PART I

Item 1.    Consolidated Financial Statements (Unaudited)

Laredo Petroleum, Inc.
Consolidated balance sheets
(in thousands, except share data)
(Unaudited)
 
 
September 30, 2014

December 31, 2013
Assets
 
 

 
 

Current assets:
 
 

 
 

Cash and cash equivalents
 
$
55,760

 
$
198,153

Accounts receivable, net
 
103,767

 
77,318

Derivatives
 
11,520

 
15,806

Deferred income taxes
 
1,255

 
3,634

Other current assets
 
18,159

 
12,698

Total current assets
 
190,461

 
307,609

Property and equipment:
 
 
 
 

Oil and natural gas properties, full cost method:
 
 
 
 

Proved properties
 
4,021,449

 
3,276,578

Unproved properties not being amortized
 
427,132

 
208,085

Midstream service assets
 
102,758

 
51,704

Other fixed assets
 
43,834

 
32,832

Total property and equipment
 
4,595,173

 
3,569,199

Less accumulated depletion, depreciation, amortization and impairment
 
(1,530,322
)
 
(1,364,875
)
Net property and equipment
 
3,064,851

 
2,204,324

Derivatives
 
5,327

 
79,726

Deferred loan costs, net
 
29,777

 
25,933

Investment in equity method investee
 
40,810

 
5,913

Other assets, net
 
1,683

 
255

Total assets
 
$
3,332,909

 
$
2,623,760

Liabilities and stockholders’ equity
 
 
 
 

Current liabilities:
 
 
 
 

Accounts payable
 
$
55,458

 
$
16,002

Accrued payable - affiliates
 
2,670

 
3,489

Undistributed revenue and royalties
 
49,229

 
35,124

Accrued capital expenditures
 
140,273

 
116,328

Derivatives
 
4,454

 
10,795

Other current liabilities
 
66,090

 
72,231

Total current liabilities
 
318,174

 
253,969

Long-term debt
 
1,576,358

 
1,051,538

Derivatives
 
1,695

 
2,680

Deferred income taxes
 
49,425

 
16,293

Asset retirement obligations
 
26,432

 
21,478

Other noncurrent liabilities
 
6,130

 
5,546

Total liabilities
 
1,978,214

 
1,351,504

Commitments and contingencies
 


 


Stockholders’ equity:
 
 
 
 
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued at September 30, 2014 and December 31, 2013
 
—

 
—

Common stock, $0.01 par value, 450,000,000 shares authorized, and 143,714,899 and 142,671,436 issued, at September 30, 2014 and December 31, 2013, respectively
 
1,437

 
1,427

Additional paid-in capital
 
1,301,943

 
1,283,809

Retained earnings (accumulated deficit)
 
51,315

 
(12,980
)
Total stockholders’ equity
 
1,354,695

 
1,272,256

Total liabilities and stockholders’ equity
 
$
3,332,909

 
$
2,623,760


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

1


Laredo Petroleum, Inc.
Consolidated statements of operations
(in thousands, except per share data)
(Unaudited)
 
 
Three months ended September 30,
 
Nine months ended September 30,
 
 
2014
 
2013
 
2014
 
2013
Revenues:






 
 

 
 

Oil and natural gas sales

$
199,490


$
170,840


$
555,576


$
511,513

Midstream service revenue

751


—


1,019


328

Total revenues

200,241


170,840


556,595


511,841

Costs and expenses:

 
 
 
 
 
 
 
Lease operating expenses

25,165


19,565


67,129


64,192

Midstream service expense
 
1,225

 
1,090

 
3,596

 
2,569

Production and ad valorem taxes

12,550


11,723


38,160


32,890

Natural gas volume commitment - affiliates

675


305


1,779


444

General and administrative

27,078


24,405

 
84,284

 
64,534

Accretion of asset retirement obligations

442


350


1,279


1,154

Depletion, depreciation and amortization

63,942


55,982


166,605


186,719

Total costs and expenses

131,077


113,420


362,832


352,502

Operating income

69,164


57,420


193,763


159,339

Non-operating income (expense):




 
 
 
 
 
Gain (loss) on derivatives:




 
 
 
 
 
Commodity derivatives, net

92,790


(9,830
)

(1,447
)

(2,709
)
Interest rate derivatives, net

—


(8
)

—


(23
)
Income (loss) from equity method investee

(61
)

48


(86
)

(65
)
Interest expense

(30,549
)

(24,929
)

(90,192
)

(76,221
)
Interest and other income

33


59


310


86

Write-off of deferred loan costs

—


(1,502
)
 
(124
)
 
(1,502
)
Gain (loss) on disposal of assets, net

(2,192
)

607


(2,418
)

548

Non-operating income (expense), net

60,021


(35,555
)

(93,957
)

(79,886
)
Income from continuing operations before income taxes

129,185


21,865


99,806


79,453

Income tax expense:












Deferred

(45,778
)

(10,048
)

(35,511
)

(31,205
)
Total income tax expense

(45,778
)

(10,048
)

(35,511
)

(31,205
)
Income from continuing operations

83,407


11,817


64,295


48,248

Income from discontinued operations, net of tax

—


726


—


1,516

Net income

$
83,407

 
$
12,543


$
64,295


$
49,764

Net income per common share:







 




Basic:







 




Income from continuing operations

$
0.59


$
0.09


$
0.46


$
0.37

Income from discontinued operations, net of tax

—


—


—


0.01

Net income per share

$
0.59


$
0.09


$
0.46

 
$
0.38

Diluted:







 

 
 

Income from continuing operations

$
0.58


$
0.09


$
0.45

 
$
0.37

Income from discontinued operations, net of tax

—


—


—

 
0.01

Net income per share

$
0.58


$
0.09


$
0.45

 
$
0.38

Weighted-average common shares outstanding:







 

 
 

Basic

141,413


134,461


141,261

 
129,701

Diluted

143,813


136,460


143,583

 
131,589

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

2


Laredo Petroleum, Inc.
Consolidated statement of stockholders’ equity
(in thousands)
(Unaudited) 
 
 
Common Stock
 
Additional
paid-in capital
 
Treasury Stock
(at cost)
 
Retained earnings (accumulated deficit)
 
 
 
 
Shares
 
Amount
 
 
Shares
 
Amount
 
 
Total
Balance, December 31, 2013
 
142,671

 
$
1,427

 
$
1,283,809

 
—

 
$
—

 
$
(12,980
)
 
$
1,272,256

Restricted stock awards
 
1,209

 
12

 
(12
)
 
—

 
—

 
—

 
—

Restricted stock forfeitures
 
(105
)
 
(1
)
 
1

 
—

 
—

 
—

 
—

Vested restricted stock exchanged for tax withholding
 
—

 
—

 
—

 
155

 
(4,075
)
 
—

 
(4,075
)
Retirement of treasury stock
 
(155
)
 
(2
)
 
(4,073
)
 
(155
)
 
4,075

 
—

 
—

Exercise of employee stock options
 
95

 
1

 
1,884

 
—

 
—

 
—

 
1,885

Stock-based compensation
 
—

 
—

 
20,334

 
—

 
—

 
—

 
20,334

Net income
 
—

 
—

 
—

 
—

 
—

 
64,295

 
64,295

Balance, September 30, 2014
 
143,715

 
$
1,437

 
$
1,301,943

 
—

 
$
—

 
$
51,315

 
$
1,354,695

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

3


Laredo Petroleum, Inc.
Consolidated statements of cash flows
(in thousands)
(Unaudited)
 
 
Nine months ended September 30,
 
 
2014
 
2013
Cash flows from operating activities:

 


 

Net income

$
64,295


$
49,764

Adjustments to reconcile net income to net cash provided by operating activities:






Deferred income tax expense

35,511


31,970

Depletion, depreciation and amortization

166,605


187,346

Bad debt expense

—


653

Non-cash stock-based compensation, net of amount capitalized

16,919


13,556

Accretion of asset retirement obligations

1,279


1,154

Mark-to-market on derivatives:






Loss on derivatives, net

1,447


2,732

Cash settlements (paid) received for matured derivatives, net

(1,320
)

588

Cash settlements received for early terminations of derivatives, net

76,660


5,366

Change in net present value of deferred premiums paid for derivatives

170


384

Cash premiums paid for derivatives

(5,599
)

(7,920
)
Amortization of deferred loan costs

3,823


3,905

Write-off of deferred loan costs

124


1,502

Other

2,734


(662
)
(Increase) decrease in accounts receivable
 
(26,449
)
 
5,873

Increase in other assets
 
(8,656
)
 
(1,383
)
Increase (decrease) in accounts payable
 
39,456

 
(17,724
)
Increase (decrease) in undistributed revenues and royalties
 
14,105

 
(5,780
)
Decrease in other accrued liabilities
 
(7,908
)
 
(1,406
)
Increase in other noncurrent liabilities
 
2,373

 
570

Increase in fair value of performance unit awards
 
767

 
4,950

Net cash provided by operating activities
 
376,336

 
275,438

Cash flows from investing activities:






Capital expenditures:






Acquisition of oil and natural gas properties

(6,493
)

(33,710
)
Acquisition of mineral interests

(7,305
)

—

Oil and natural gas properties

(925,121
)

(538,395
)
Midstream service assets

(45,263
)

(15,394
)
Other fixed assets

(13,612
)

(13,874
)
Investment in equity method investee
 
(37,581
)
 
(3,287
)
Proceeds from dispositions of capital assets, net of costs

1,627


429,702

Net cash used in investing activities

(1,033,748
)

(174,958
)
Cash flows from financing activities:






Borrowings on Senior Secured Credit Facility

75,000


230,000

Payments on Senior Secured Credit Facility

—


(395,000
)
Issuance of January 2022 Notes

450,000


—

Proceeds from issuance of common stock, net of offering costs
 
—

 
298,104

Purchase of treasury stock

(4,075
)

(1,478
)
Proceeds from exercise of employee stock options

1,885


654

Payments for loan costs

(7,791
)

(714
)
Net cash provided by financing activities

515,019


131,566

Net (decrease) increase in cash and cash equivalents

(142,393
)

232,046

Cash and cash equivalents, beginning of period

198,153


33,224

Cash and cash equivalents, end of period

$
55,760


$
265,270

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

4
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)

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 acquisition, exploration and development 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 and (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 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 as of 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 September 30, 2014, results of operations for the three and nine months ended September 30, 2014 and 2013 and cash flows for the nine months ended September 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. 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 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 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.

5
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, 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. 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 of 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)
 
September 30, 2014
 
December 31, 2013
Oil and natural gas sales
 
$
72,449

 
$
57,647

Joint operations, net(1)
 
27,164

 
16,629

Other
 
4,154

 
3,042

Total
 
$
103,767

 
$
77,318

______________________________________________________________________________
(1)
Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.7 million as of September 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 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).

6
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)
 
September 30, 2014
 
December 31, 2013
Proved oil and natural gas properties
 
$
4,021,449

 
$
3,276,578

Less accumulated depletion and impairment
 
(1,509,417
)
 
(1,349,315
)
Proved oil and natural gas properties, net
 
2,512,032

 
1,927,263

 
 
 
 
 
Unproved properties not being amortized(1)
 
427,132

 
208,085

 
 
 
 
 
Midstream service assets
 
102,758

 
51,704

Less accumulated depreciation
 
(7,142
)
 
(4,404
)
Midstream service assets, net
 
95,616

 
47,300

 
 
 
 
 
Other fixed assets
 
43,834

 
32,832

Less accumulated depreciation and amortization
 
(13,763
)
 
(11,156
)
Other fixed assets, net
 
30,071

 
21,676

 
 
 
 
 
Total property and equipment, net
 
$
3,064,851

 
$
2,204,324

______________________________________________________________________________
(1)
The Company acquired significant leasehold interests during the three months ended September 30, 2014.
For the three months ended September 30, 2014 and 2013, depletion expense was $20.25 per barrel of oil equivalent ("BOE") sold and $20.83 per BOE sold, respectively. For the nine months ended September 30, 2014 and 2013, depletion expense was $19.83 per BOE sold and $20.36 per BOE sold, 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 nine months ended September 30, 2014 mainly as a result of the issuance of the January 2022 Notes (as defined below). The Company capitalized $0.7 million of deferred loan costs during the nine months ended September 30, 2013. The Company had total deferred loan costs of $29.8 million and $25.9 million, net of accumulated amortization of $18.1 million and $14.2 million, as of September 30, 2014 and December 31, 2013, respectively.
As a result of changes in the borrowing base of the Senior Secured Credit Facility due to the issuance of the January 2022 Notes, the Company wrote-off $0.1 million in deferred loan costs during the nine months ended September 30, 2014. During the nine months ended September 30, 2013, $1.5 million of deferred loan costs were written-off as a result of changes in the borrowing base of the Senior Secured Credit Facility due to the Anadarko Basin Sale. See Note D.5 and C.3 for definition of and information regarding the Senior Secured Credit Facility and the Anadarko Basin Sale, respectively.
Future amortization expense of deferred loan costs as of September 30, 2014 is as follows:
(in thousands)
 
 
Remaining 2014

$
1,316

2015

5,295

2016

5,361

2017

5,432

2018

5,222

Thereafter

7,151

Total

$
29,777


7
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)

9.    Other current assets and liabilities
Other current assets consist of the following components for the periods presented:
(in thousands)
 
September 30, 2014
 
December 31, 2013
Materials and supplies inventory
 
$
10,787

 
$
9,633

Prepaid expenses
 
7,372

 
3,065

Total other current assets
 
$
18,159

 
$
12,698

Other current liabilities consist of the following components for the periods presented:
(in thousands)
 
September 30, 2014
 
December 31, 2013
Accrued interest payable
 
$
27,525

 
$
25,885

Accrued compensation and benefits
 
14,444

 
16,711

Lease operating expense payable
 
11,263

 
10,637

Asset retirement obligations
 
838

 
265

Other accrued liabilities
 
12,020

 
18,733

Total other current liabilities
 
$
66,090

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

8
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)

The following reconciles the Company’s asset retirement obligation liability for continuing and discontinued operations for the periods presented:
(in thousands)
 
Nine months ended September 30, 2014
 
Year ended December 31, 2013
Liability at beginning of period
 
$
21,743

 
$
21,505

Liabilities added due to acquisitions, drilling, midstream asset construction and other
 
4,665

 
2,709

Accretion expense
 
1,279

 
1,475

Liabilities settled upon plugging and abandonment
 
(519
)
 
(226
)
Liabilities removed due to Anadarko Basin Sale
 
—

 
(7,801
)
Revision of estimates
 
102

 
4,081

Liability at end of period
 
$
27,270

 
$
21,743

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 assets and 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.
12.    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. 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 of its oil and gas properties into the full-cost pool. Capitalized stock-based compensation is included as an addition to "Oil and natural gas properties" in the unaudited consolidated balance sheets. See Note E for further discussion regarding 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 September 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:
 
 
Nine months ended September 30,
(in thousands)
 
2014

2013
Cash paid for interest, net of $51 and $255 of capitalized interest, respectively
 
$
85,041

 
$
74,932

    

9
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)

The following presents the supplemental disclosure of non-cash investing and financing information for the periods presented:
 
 
Nine months ended September 30,
(in thousands)
 
2014

2013
Change in accrued capital expenditures
 
$
23,945

 
$
(41,001
)
Capitalized asset retirement cost
 
$
4,767

 
$
1,978

Capitalized stock-based compensation
 
$
3,415

 
$
—

Equity issued in connection with acquisition
 
$
—

 
$
3,029

C—Acquisitions and divestiture
1.    2014 acquisition of leasehold interests
During the three months ended September 30, 2014, the Company completed a material acquisition of leasehold interests in the Midland Basin, primarily within the Company's core development area. The acquisition was accounted for as an acquisition of assets.
2.    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. These mineral interests entitle the Company to receive royalty interests on all production from this acreage with no additional future capital or operating expenses required. As such, the acquisition was accounted for as an acquisition of assets.
3.    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.
4.    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 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

10
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)

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 periods presented:
(in thousands)
 
Three months ended September 30, 2013
 
Nine months ended September 30, 2013
Revenues
 
$
11,429

 
$
61,166

Expenses(1)
 
9,283

 
50,120

_________________________________________________________________________
(1)
Expenses include lease operating expense, production and ad valorem tax expense, accretion expense and depletion, depreciation and amortization expense.
For the three and nine months ended September 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 three and nine months ended September 30, 2013 in the line item "Gain (loss) on disposal of assets, net."
The following represents operating results from discontinued operations for the periods presented:
(in thousands)
 
Three months ended September 30, 2013
 
Nine months ended September 30, 2013
Revenues:
 
 
 
 
Midstream service revenue
 
$
761

 
$
4,071

Total revenues from discontinued operations
 
761

 
4,071

Cost and expenses:
 
 
 
 
Midstream service expense, net
 
(286
)
 
1,163

Depletion, depreciation and amortization
 
—

 
627

Total costs and expenses from discontinued operations
 
(286
)
 
1,790

Income from discontinued operations before income tax
 
1,047

 
2,281

Income tax expense
 
(321
)
 
(765
)
Income from discontinued operations
 
$
726

 
$
1,516

D—Debt
1.    Interest expense
The following amounts have been incurred and charged to interest expense for the periods presented:
 
 
Three months ended September 30,
 
Nine months ended September 30,
(in thousands)
 
2014
 
2013
 
2014
 
2013
Cash payments for interest
 
$
38,952


$
26,627

 
$
85,092

 
$
75,187

Amortization of deferred loan costs and other adjustments
 
1,188


2,736

 
3,511

 
5,360

Change in accrued interest
 
(9,540
)

(4,391
)
 
1,640

 
(4,071
)
Interest costs incurred
 
30,600


24,972

 
90,243

 
76,476

Less capitalized interest
 
(51
)

(43
)
 
(51
)
 
(255
)
Total interest expense
 
$
30,549


$
24,929

 
$
90,192

 
$
76,221

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

11
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)

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 used 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.
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 was launched on April 22, 2014 with all notes exchanged on May 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 and certain of the Company’s future restricted subsidiaries.
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 and certain of the Company’s future restricted subsidiaries.
5.    Senior Secured Credit Facility
As of September 30, 2014, the Fourth Amended and Restated Credit Agreement (as amended, the "Senior Secured Credit Facility"), which matures on November 4, 2018, had a borrowing base of $1.0 billion and an aggregate elected commitment of $825.0 million with $75.0 million outstanding and was subject to an interest rate of 1.69%. It contains both financial and non-financial covenants, all of which the Company was in compliance with as of September 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.

12
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)

Subsequent to September 30, 2014, the Company made additional borrowings on the Senior Secured Credit Facility and the borrowing base and the aggregate elected commitment amounts were increased. 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 values of the Company’s debt instruments for the periods presented:
 
 
September 30, 2014
 
December 31, 2013
(in thousands)
 
Carrying
value
 
Fair
value
 
Carrying
value
 
Fair
value
2019 Notes(1)
 
$
551,358

 
$
585,750

 
$
551,538

 
$
615,313

January 2022 Notes
 
450,000

 
444,150

 
—

 
—

May 2022 Notes
 
500,000

 
526,245

 
500,000

 
549,375

Senior Secured Credit Facility
 
75,000

 
75,046

 
—

 
—

Total value of debt
 
$
1,576,358

 
$
1,631,191

 
$
1,051,538

 
$
1,164,688

______________________________________________________________________________
(1)
The carrying value of the 2019 Notes includes the October Notes unamortized bond premium of $1.4 million and $1.5 million as of September 30, 2014 and December 31, 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 September 30, 2014 and December 31, 2013 quoted market price (Level 1) for each respective instrument. The fair value of the outstanding debt on the Senior Secured Credit Facility as of September 30, 2014 was estimated utilizing pricing models for similar instruments (Level 2). See Note H for information about fair value hierarchy levels.
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. 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 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. Per the award agreement terms, if an employee terminates employment prior to the restriction lapse date, the awarded shares are forfeited and canceled and are no longer considered issued and outstanding. If the employee's termination of employment is by reason of death or disability, all of the holder's restricted stock will automatically vest. Restricted stock awards granted to officers and employees vest in a variety of vesting schedules including (i) 20% at the grant date and then 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.

13
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)

The following table reflects the outstanding restricted stock awards for the nine months ended September 30, 2014:
(in thousands, except for weighted-average grant date fair values)
 
Restricted
stock
awards
 
Weighted-average
grant date
fair value (per award)
Outstanding at December 31, 2013
 
1,799

 
$
19.17

Granted
 
1,209

 
$
25.81

Forfeited
 
(105
)
 
$
22.54

Vested(1)
 
(635
)
 
$
18.90

Outstanding at September 30, 2014
 
2,268

 
$
22.65

______________________________________________________________________________
(1)
The vesting of certain restricted stock awards could result in federal and state income tax expense or benefit related to the difference between the market price of the common stock at the date of vesting and the date of grant. See Note F for additional discussion regarding the tax impact of vested restricted stock awards.
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 September 30, 2014, unrecognized stock-based compensation related to the restricted stock awards was $33.8 million. Such cost is expected to be recognized over a weighted-average period of 1.7 years.
2.    Restricted stock option awards
Restricted stock option awards granted under the LTIP vest and are exercisable in four equal installments on each of the four anniversaries of the date of the grant. The following table reflects the stock option award activity for the nine months ended September 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)
Outstanding at December 31, 2013
 
1,229

 
$
19.32

 
8.82

Granted
 
336

 
$
25.60

 
9.41

Exercised(1)
 
(95
)
 
$
19.93

 
7.98

Expired or canceled
 
—

 
$
—

 
—

Forfeited
 
(47
)
 
$
19.70

 
—

Outstanding at September 30, 2014
 
1,423

 
$
20.75

 
8.40

Vested and exercisable at end of period(2)
 
352

 
$
20.38

 
7.91

Vested, exercisable, and expected to vest at end of period(3)
 
1,390

 
$
20.75

 
8.40

_____________________________________________________________________________
(1)
The exercise of stock option awards could result in federal and state income tax expense or benefit related to the difference between the fair value of the stock option award at the date of grant and the intrinsic value of the stock option award when exercised. See Note F for additional discussion regarding the tax impact of exercised stock option awards.
(2)
The aggregate intrinsic value of vested and exercisable options at September 30, 2014 was $1.0 million.
(3)
The aggregate intrinsic value of vested, exercisable and expected to vest options at September 30, 2014 was $3.9 million.
The Company utilizes the Black-Scholes option pricing model to determine the fair values of restricted stock 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 option awards will be outstanding prior to exercise and the associated volatility. As of September 30, 2014, unrecognized stock-based compensation related to the restricted option awards was $9.4 million. Such cost is expected to be recognized over a weighted-average period of 2.56 years.
    

14
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)

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.
In accordance with the LTIP and stock option agreement, the options granted will become exercisable in accordance with the following schedule based upon the number of full years of the optionee's continuous employment or service with the Company, following the date of grant:
Full years of continuous employment
 
Incremental percentage of
option exercisable
 
Cumulative percentage of
option exercisable
Less than one
 
—
%
 
—
%
One
 
25
%
 
25
%
Two
 
25
%
 
50
%
Three
 
25
%
 
75
%
Four
 
25
%
 
100
%
No shares of common stock may be purchased unless the optionee has remained in continuous employment with the Company for one year from the grant date. Unless terminated sooner, the option will expire if and to the extent it is not exercised within 10 years from the grant date. The unvested portion of a stock option award shall expire upon termination of employment, and the vested portion of a stock option award shall remain exercisable for (i) one year following termination of employment by reason of the holder's death or disability, but not later than the expiration of the option period, or (ii) 90 days following termination of employment for any reason other than the holder's death or disability, and other than the holder's termination of employment for cause. Both the unvested and the vested but unexercised portion of a stock option award shall expire upon the termination of the option holder's employment or service by the Company for cause.
3.    Performance share awards
The Company performance share awards granted to management on February 27, 2014 ("Performance Share Awards") are subject to a combination of market and service vesting criteria. A Monte Carlo simulation prepared by an independent third party was utilized 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 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 nine months ended September 30, 2014, 271,667 performance shares were awarded and all remain outstanding at September 30, 2014. As of September 30, 2014, unrecognized stock-based compensation related to the Performance Share Awards was $6.0 million. Such cost is expected to be recognized over a weighted-average period of 2.41 years.

15
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)

The assumptions used to estimate the fair value of the Performance Share Awards are as follows:
Risk-free rate(1)
 
0.63
%
Dividend yield
 
—
%
Expected volatility(2)
 
38.21
%
Laredo stock closing price as of February 27, 2014
 
$
25.60

Fair value per performance share
 
$
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.
4.    Stock-based compensation award expense
The following has been recorded to stock-based compensation expense for the periods presented:
 
 
Three months ended September 30,

Nine months ended September 30,
(in thousands)
 
2014

2013

2014

2013
Restricted stock award compensation
 
$
5,880

 
$
4,707

 
$
16,122

 
$
11,105

Restricted stock option award compensation
 
931

 
1,169

 
2,736


2,451

Restricted performance share award compensation
 
631

 
—

 
1,476


—

Total stock-based compensation
 
7,442

 
5,876

 
20,334


13,556

Less amounts capitalized in oil and natural gas properties
 
(1,248
)
 
—

 
(3,415
)

—

Net stock-based compensation expense
 
$
6,194

 
$
5,876

 
$
16,919


$
13,556

5.    Performance unit awards
The performance unit awards issued to management on February 15, 2013 ("2013 Performance Unit Awards") and on February 3, 2012 ("2012 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'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 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 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 Unit Awards 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 the 2012 Performance Unit Awards and the 2013 Performance Unit Awards 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. Due to the quarterly re-measurement of the fair value of these awards as of September 30, 2014, compensation expense for the three months ended September 30, 2014 was a reversal of $0.4 million. Compensation expense related to these awards amounted to $2.8 million in the three months ended September 30, 2013, and $0.8 million and $5.0 million in the nine months ended September 30, 2014 and 2013, respectively.

16
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)

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 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 no unrecognized tax benefits related to uncertain tax positions in the consolidated financial statements at September 30, 2014 or December 31, 2013.
The Company is subject to corporate income taxes and the Texas franchise tax. Income tax expense attributable to income from continuing operations for the periods presented consisted of the following:
 
 
Three months ended September 30,
 
Nine months ended September 30,
(in thousands)

2014
 
2013
 
2014
 
2013
Current taxes

$
—

 
$
—


$
—

 
$
—

Deferred taxes

(45,778
)
 
(10,048
)
 
(35,511
)
 
(31,205
)
Income tax expense

$
(45,778
)
 
$
(10,048
)

$
(35,511
)
 
$
(31,205
)
The following presents the comprehensive provision for income taxes for the periods presented:
 

Three months ended September 30,
 
Nine months ended September 30,
(in thousands)

2014
 
2013
 
2014
 
2013
Comprehensive provision for income taxes allocable to:

 


 







Continuing operations

$
(45,778
)
 
$
(10,048
)
 
$
(35,511
)
 
$
(31,205
)
Discontinued operations

—

 
(321
)
 
—

 
(765
)
Comprehensive provision for income taxes

$
(45,778
)
 
$
(10,369
)
 
$
(35,511
)
 
$
(31,970
)
Income tax expense attributable to income from continuing operations before income taxes differed from amounts computed by applying the applicable federal income tax rate of 35% for the three and nine months ended September 30, 2014 and 34% for the three and nine months ended September 30, 2013 to pre-tax earnings as a result of the following:
 

Three months ended September 30,
 
Nine months ended September 30,
(in thousands)

2014
 
2013
 
2014
 
2013
Income tax expense computed by applying the statutory rate

$
(45,215
)
 
$
(7,434
)
 
$
(34,932
)
 
$
(27,014
)
State income tax, net of federal tax benefit and increase in valuation allowance

247

 
(2,651
)
 
1,881

 
(3,223
)
Non-deductible stock-based compensation

(152
)
 
(156
)
 
(391
)
 
(495
)
Stock-based compensation tax deficiency

(4
)
 
(72
)
 
(160
)
 
(483
)
Change in deferred tax valuation allowance

(22
)
 
(20
)
 
(1,134
)
 
(49
)
Other items

(632
)
 
285

 
(775
)
 
59

Income tax expense

$
(45,778
)
 
$
(10,048
)
 
$
(35,511
)
 
$
(31,205
)
 
The effective tax rate on income from continuing operations before income taxes was 35% and 46% for the three months ended September 30, 2014 and 2013, respectively, and 36% and 39% for the nine months ended September 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.

17
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)

The impact of significant discrete items is separately recognized in the quarter in which they occur. The vesting of certain restricted stock awards could result in federal and state income tax expense or benefits related to the difference between the market price of the common stock at the date of vesting and the date of grant. The exercise of stock option awards could result in federal and state income tax expense or benefits related to the difference between the fair value of the stock option at the date of grant and the intrinsic value of the stock option when exercised. The tax impact resulting from vestings of restricted stock awards and exercise of option awards are discrete items. During the three and nine months ended September 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 nine months ended September 30, 2014, certain restricted stock options were exercised. The income tax deduction related to the intrinsic value of the options was less than the expense previously recognized for book purposes. In accordance with GAAP, such shortfalls reduce additional paid-in capital to the extent windfall tax benefits have been previously recognized. However, the Company has not previously recognized any windfall tax benefits. Therefore, such shortfalls are included in income tax expense attributable to continuing operations.
The following table presents the tax impact of these shortfalls for the periods presented:
 
 
Three months ended September 30,
 
Nine months ended September 30,
(in thousands)
 
2014
 
2013
 
2014
 
2013
Vesting of restricted stock
 
$
4

 
$
2

 
$
5

 
$
427

Exercise of restricted stock options
 
1

 
72

 
158

 
72

Tax impact of shortfalls
 
$
5

 
$
74

 
$
163

 
$
499

The Company filed its 2013 federal and Oklahoma income tax returns during the three months ended September 30, 2014. As a result, the Company recognized an aggregate expense from tax return related items, which is a discrete item, of $0.6 million for each of the three and nine month periods ending September 30, 2014, which is included in income tax expense attributable to continuing operations for these respective periods. The tax expense impact of the prior-year return to provision true-up was $2.4 million for each of the three and nine month periods ended September 30, 2013.
Significant components of the Company’s deferred tax liabilities for the periods presented are as follows:
(in thousands)
 
September 30, 2014
 
December 31, 2013
Net operating loss carry-forward
 
$
337,933

 
$
284,890

Oil and natural gas properties and equipment
 
(396,802
)
 
(278,735
)
Derivatives
 
(4,054
)
 
(30,859
)
Stock-based compensation
 
9,624

 
6,578

Accrued bonus
 
3,133

 
3,740

Capitalized interest
 
2,705

 
2,099

Other
 
586

 
(240
)
Gross deferred tax liability
 
(46,875
)
 
(12,527
)
Valuation allowance
 
(1,295
)
 
(132
)
Net deferred tax liability
 
$
(48,170
)
 
$
(12,659
)
Net deferred tax assets and liabilities were classified in the unaudited consolidated balance sheets as follows for the periods presented:
(in thousands)
 
September 30, 2014
 
December 31, 2013
Deferred tax asset
 
$
1,255

 
$
3,634

Deferred tax liability
 
(49,425
)
 
(16,293
)
Net deferred tax liability
 
$
(48,170
)
 
$
(12,659
)
The Company had federal net operating loss carry-forwards totaling $956.8 million and state of Oklahoma net operating loss carry-forwards totaling $120.5 million as of September 30, 2014. These carry-forwards begin expiring in 2026. As of September 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

18
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)

flows from its oil and natural gas reserves (including the timing of those cash flows), the reversal of deferred tax liabilities recorded as of September 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 September 30, 2014, the Company had suspended additional paid-in capital credits of $4.5 million related to windfall tax deductions. Upon realization of the net operating loss carry-forwards from such windfall tax deductions, the Company would record a benefit of up to $4.5 million in additional paid-in capital.
The Company maintains a valuation allowance to reduce certain deferred tax assets to amounts that are more likely than not to be realized. As of September 30, 2014, a full valuation allowance of $1.3 million was recorded against the deferred tax asset related to the Company’s charitable contribution carry-forward of $3.6 million.
The Company's income tax returns for the years 2011 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.
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 September 30, 2014, the Company had 53 open derivative contracts with financial institutions which extend from October 2014 to December 2017. None of these contracts were designated as hedges for accounting purposes. The contracts are recorded at fair value on the balance sheet 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 "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 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 Argus Midland ("Argus Midland") index crude oil price and the West Texas Intermediate Argus Cushing ("Argus Cushing") index crude oil price. When the Argus Cushing price less the fixed basis differential is greater than the actual Argus Midland price, the difference multiplied by the hedged contract volume is paid to the Company by the counterparty. When the Argus Cushing price less the fixed basis differential is less than the actual Argus Midland price, the difference multiplied by the hedged contract volume is paid by the Company to the counterparty.
During the first quarter of 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

19
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)

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 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.
During the nine months ended September 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 collars
 
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
Price collars
 
2,263,000

 
$
—

 
$
80.00

 
$
100.00

 
January 2017
-
December 2017
Natural gas (volumes in MMBtu):
 
 
 
 
 
 
 
 
 
 
Swaps
 
5,508,000

 
$
4.32

 
$
—

 
$
—

 
March 2014
-
December 2014
Price collar
 
3,797,500

 
$
—

 
$
4.00

 
$
5.50

 
May 2014
-
December 2014
Price collar
 
20,440,000

 
$
—

 
$
3.00

 
$
5.95

 
January 2015
-
December 2015
Price collar
 
18,666,000

 
$
—

 
$
3.00

 
$
5.60

 
January 2016
-
December 2016

    

20
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)

The following table summarizes open positions as of September 30, 2014, and represents, as of such date, derivatives in place through December 2017 on annual production volumes:
 
 
Remaining Year
2014
 
Year
2015
 
Year
2016
 
Year
2017
Oil positions:(1)
 
 

 
 
 
 

 
 
Puts:
 
 

 
 

 
 

 
 
Hedged volume (Bbl)
 
135,000

 
456,000

 
—

 
—

Weighted-average price ($/Bbl)
 
$
75.00

 
$
75.00

 
$
—

 
$
—

Swaps:
 
 

 
 

 
 

 
 
Hedged volume (Bbl)
 
685,999

 
672,000

 
1,573,800

 
—

Weighted-average price ($/Bbl)
 
$
96.35

 
$
96.56

 
$
84.82

 
$
—

Collars:
 
 

 
 

 
 

 
 
Hedged volume (Bbl)
 
736,500

 
6,557,020

 
2,556,000

 
2,263,000

Weighted-average floor price ($/Bbl)
 
$
86.42

 
$
79.81

 
$
80.00

 
$
80.00

Weighted-average ceiling price ($/Bbl)
 
$
104.89

 
$
95.40

 
$
93.77

 
$
100.00

Basis swap:(2)
 
 
 
 
 
 
 
 
Hedged volume (Bbl)
 
552,000

 
—

 
—

 
—

Weighted-average price ($/Bbl)
 
$
(1.00
)
 
$
—

 
$
—

 
$
—

Natural gas positions:(3)
 
 

 
 

 
 

 
 
Swaps:
 
 

 
 

 
 

 
 
Hedged volume (MMBtu)
 
1,656,000

 
—

 
—

 
—

Weighted-average price ($/MMBtu)
 
$
4.32

 
$
—

 
$
—

 
$
—

Collars:
 
 

 
 

 
 

 
 
Hedged volume (MMBtu)
 
3,826,000

 
28,600,000

 
18,666,000

 
—

Weighted-average floor price ($/MMBtu)
 
$
3.37

 
$
3.00

 
$
3.00

 
$
—

Weighted-average ceiling price ($/MMBtu)
 
$
5.50

 
$
5.96

 
$
5.60

 
$
—

_______________________________________________________________________________
(1)
Oil derivatives are settled based on the average of the daily settlement prices for the First Nearby Month of the West Texas Intermediate NYMEX Light Sweet Crude Oil Futures Contract for each NYMEX Trading Day during each month.
(2)
The associated oil basis swap is settled on the differential between the Argus Midland and the Argus Cushing index oil prices.
(3)
Natural gas derivatives are settled based on the Inside FERC index price for West Texas Waha for the calculation period.
The following represents cash settlements received (paid) for matured derivatives for the periods presented:
 
 
Three months ended September 30,
 
Nine months ended September 30,
(in thousands)
 
2014
 
2013
 
2014
 
2013
Commodity derivatives received (paid)
 
$
4,531

 
$
(3,975
)
 
$
(1,320
)
 
$
888

Interest rate derivatives paid
 
—

 
(94
)
 
—

 
(300
)
Cash settlements received (paid) for matured derivatives, net
 
$
4,531

 
$
(4,069
)
 
$
(1,320
)
 
$
588

 
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

21
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)

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 during the period ended September 30, 2014.
3.    Balance sheet presentation
The Company’s oil and natural gas commodity 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 September 30, 2014 and December 31, 2013, respectively:
(in thousands)
 
September 30, 2014
 
December 31, 2013
Assets:
 
 

 
 

Commodity derivatives:
 
 

 
 

Oil derivatives
 
$
25,988

 
$
140,496

Natural gas derivatives
 
1,930

 
657

Total assets
 
$
27,918

 
$
141,153

 
 
 
 
 
Liabilities:
 
 
 
 
Commodity derivatives:
 
 
 
 
Oil derivatives(1)
 
$
16,081

 
$
56,818

Natural gas derivatives(2)
 
1,139

 
2,278

 Total liabilities
 
$
17,220

 
$
59,096

 
 
 
 
 
Net derivative position
 
$
10,698

 
$
82,057

______________________________________________________________________________
(1)
The oil derivatives fair value includes a deferred premium liability of $10.1 million and $11.1 million as of September 30, 2014 and December 31, 2013, respectively.
(2)
The natural gas derivatives fair value includes a deferred premium liability of $1.0 million and $1.6 million as of September 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 or originally were 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 September 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).

22
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 nine months ended September 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
As of September 30, 2014:
 
 

 
 

 
 

 
 

Commodity derivatives
 
$
—

 
$
21,753

 
$
—

 
$
21,753

Deferred premiums
 
—

 
—

 
(11,055
)
 
(11,055
)
Total
 
$
—

 
$
21,753

 
$
(11,055
)
 
$
10,698

(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 each derivative contract's corresponding commodity index price, appropriate 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 held in prior periods 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 1.69% to 3.56%), and then records the change in net present value to interest expense over the period from trade until the final settlement date at the end of the contract. After this initial valuation, the net present value of each deferred

23
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)

premium is not adjusted; therefore, significant increases (decreases) in the Senior Secured Credit Facility rate would result in a significantly lower (higher) fair value measurement for each new contract entered into 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 September 30, 2014, and for the calendar years following:
(in thousands)
 
 
Remaining 2014
 
$
1,820

2015
 
5,166

2016
 
358

2017
 
3,651

2018
 
339

  Total
 
$
11,334

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

Three months ended September 30,

Nine months ended September 30,
(in thousands)

2014

2013

2014

2013
Balance of Level 3 at beginning of period

$
(9,025
)

$
(19,742
)

$
(12,684
)

$
(24,709
)
Change in net present value of deferred premiums for derivatives

(50
)

(102
)

(170
)

(384
)
Total purchases and settlements:












Purchases

(3,800
)

—


(3,800
)

—

Settlements(1)

1,820


4,881


5,599


10,130

Balance of Level 3 at end of period

$
(11,055
)

$
(14,963
)

$
(11,055
)

$
(14,963
)
______________________________________________________________________________
(1)
The settlement amounts for each of the three and nine months ended September 30, 2013 include $2.2 million in deferred premiums, which were settled net with the early terminated contracts from which they derive. There were no comparable amounts during the three or nine months ended September 30, 2014.
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 models. No impairments of long-lived assets were recorded in the nine months ended September 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 made to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. The Company’s joint operations accounts receivable are from a number of oil and natural gas companies, partnerships, individuals and others who own interests in the oil and gas 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

24
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)

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.
J—Commitments and contingencies
1.    Litigation

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

2.    Drilling contracts

The Company has committed to drilling contracts with various third parties in order to complete its various drilling projects. The contracts contain early termination clauses that require the Company to pay potentially 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, especially if a significant number of such contracts were terminated early in their respective terms. Management does not currently anticipate the early termination of any existing contracts in the remainder of 2014 or 2015 which would result in a substantial penalty. Future commitments of $59.6 million as of September 30, 2014 are not recorded in the accompanying unaudited consolidated balance sheets.
 
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 per share
Basic net income per share is computed by dividing net income by the weighted-average number of common shares outstanding for the period. Diluted net income per share reflects the potential dilution of non-vested restricted stock awards, Performance Share Awards and outstanding restricted stock options. For the three and nine months ended September 30, 2014, the Performance Share Awards' total shareholder return was below their agreement's payout threshold, and therefore, the Performance Share Awards were excluded from the calculation of diluted net income per share.
The effect of (i) the Company's outstanding options that were granted in February of 2014 to purchase 336,140 shares of common stock at $25.60 per share was excluded from the calculation of diluted net income per share for the three and nine months ended September 30, 2014, and (ii) the Company's outstanding restricted stock options that were granted in February 2012 to purchase 306,177 shares of common stock at $24.11 per share (the "February 2012 Option Grant") was excluded from the calculation of diluted net income per share for the three and nine months ended September 30, 2014 and for the nine months ended September 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 (i) the Company's outstanding options that were granted in February 2013 to purchase 780,281 shares of common stock at $17.34 per share (the "February 2013 Option Grant") was excluded from the calculation of diluted net income per share for the three and nine months ended September 30, 2013, and (ii) the Company's February 2012 Option Grant was excluded from the calculation of diluted net income per share for the three months ended September 30, 2013, because, utilizing the treasury method, the sum of the assumed proceeds 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.


25
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)

The following is the calculation of basic and diluted weighted-average common shares outstanding and net income per share for the periods presented:
 
 
Three months ended September 30,
 
Nine months ended September 30,
(in thousands, except for per share data)
 
2014
 
2013
 
2014
 
2013
Net income (numerator):
 
 
 
 
 
 

 
 

Income from continuing operations—basic and diluted
 
$
83,407

 
$
11,817

 
$
64,295

 
$
48,248

Income from discontinued operations, net of tax—basic and diluted
 
—

 
726

 
—

 
1,516

Net income—basic and diluted
 
$
83,407

 
$
12,543

 
$
64,295

 
$
49,764

Weighted-average common shares outstanding (denominator):
 
 
 
 
 
 
 
 
Weighted-average common shares outstanding—basic
 
141,413


134,461

 
141,261

 
129,701

Non-vested restricted stock awards
 
2,334

 
1,999

 
2,246

 
1,888

Outstanding restricted stock options(1) 
 
66

 
—

 
76

 
—

Weighted-average common shares outstanding—diluted
 
143,813


136,460

 
143,583

 
131,589

Net income per share:
 
 
 
 
 
 
 
 

Basic:
 
 
 
 
 
 
 
 
Income from continuing operations
 
$
0.59

 
$
0.09

 
$
0.46

 
$
0.37

Income from discontinued operations, net of tax
 
—

 
—

 
—

 
0.01

Net income per share
 
$
0.59

 
$
0.09

 
$
0.46

 
$
0.38

 
 
 
 
 
 
 
 
 
Diluted:
 
 
 
 
 
 
 
 
Income from continuing operations
 
$
0.58

 
$
0.09

 
$
0.45

 
$
0.37

Income from discontinued operations, net of tax
 
—

 
—

 
—

 
0.01

Net income per share
 
$
0.58

 
$
0.09

 
$
0.45

 
$
0.38

______________________________________________________________________________
(1)
The dilutive effect of the February 2013 Option Grant was calculated utilizing the treasury stock method.
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.
Laredo Midstream contributed $18.1 million and $37.6 million during the three and nine months ended September 30, 2014, respectively, and $3.2 million during the nine months ended September 30, 2013, to Medallion Gathering & Processing, LLC ("Medallion"), a Texas limited liability company. There were no contributions made during the three months ended September 30, 2013. 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 income (loss) reflected in the unaudited consolidated

26
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)

statements of operations as "Income (loss) from equity method investee" and the carrying amount reflected on the unaudited consolidated balance sheets as "Investment in equity method investee."
During September 2014, MPC completed the construction of its pipeline from Garden City, Texas to Colorado City, Texas (the "Wolfcamp Connector") and an extension connecting Reagan County, Texas to the Wolfcamp Connector at Garden City, Texas. Laredo Midstream has committed to fund an estimated $21.4 million towards an additional extension which will connect a third-party's production in Upton and Midland counties, Texas into the Wolfcamp Connector at Garden City, Texas. The Company expects to fund a significant portion of this commitment to Medallion in the fourth quarter of 2014. As of September 30, 2014, the Company recorded a payable of $2.7 million related to its minimum volume commitment to Medallion. As of December 31, 2013, the Company recorded a capital contribution payable of $2.6 million related to the fourth quarter cash requirements of the project and a payable of $0.9 million related to its minimum volume commitment to Medallion. These payables are 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 "Natural gas volume commitment - affiliates" line item. See Note O.2 for capital called by Medallion subsequent to September 30, 2014.
M—Recent accounting pronouncements
In 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 the impact this guidance 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 did not have an effect on its consolidated financial statements.

27
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)

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 September 30, 2014 and December 31, 2013, unaudited condensed consolidating statements of operations for the three and nine months ended September 30, 2014 and 2013 and unaudited condensed consolidating statements of cash flows for the nine months ended September 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. During the nine months ended September 30, 2014, certain midstream service assets were transferred from Laredo to Laredo Midstream at historical cost.

Condensed consolidating balance sheet
September 30, 2014
(Unaudited)
(in thousands)
 
Laredo
 
Laredo Midstream
 
Intercompany
eliminations
 
Consolidated
company
Accounts receivable, net
 
$
102,453

 
$
1,314

 
$
—

 
$
103,767

Other current assets
 
86,687

 
7

 
—

 
86,694

Total oil and natural gas properties, net
 
2,939,263

 
—

 
(99
)
 
2,939,164

Total midstream service assets, net
 
—

 
95,616

 
—

 
95,616

Total other fixed assets, net
 
29,797

 
274

 
—

 
30,071

Investment in subsidiaries and equity method investee
 
121,975

 
40,810

 
(121,975
)
 
40,810

Total other long-term assets
 
36,787

 
—

 
—

 
36,787

Total assets
 
$
3,316,962

 
$
138,021

 
$
(122,074
)
 
$
3,332,909

 
 
 
 
 
 
 
 
 
Accounts payable
 
$
53,207

 
$
2,251

 
$
—

 
$
55,458

Other current liabilities
 
250,957

 
11,759

 
—

 
262,716

Other long-term liabilities
 
81,646

 
2,036

 
—

 
83,682

Long-term debt
 
1,576,358

 
—

 
—

 
1,576,358

Stockholders’ equity
 
1,354,794

 
121,975

 
(122,074
)
 
1,354,695

Total liabilities and stockholders’ equity
 
$
3,316,962

 
$
138,021

 
$
(122,074
)
 
$
3,332,909




28
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)

Condensed consolidating balance sheet
December 31, 2013
(Unaudited)
(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

 
Condensed consolidating statement of operations
For the three months ended September 30, 2014
(Unaudited)
(in thousands)

Laredo

Laredo Midstream

Intercompany
eliminations

Consolidated
company
Total operating revenues

$
199,968


$
2,494


$
(2,221
)

$
200,241

Total operating costs and expenses

129,062


4,137


(2,122
)

131,077

Income (loss) from operations

70,906


(1,643
)

(99
)

69,164

Interest expense, net

(30,516
)

—


—


(30,516
)
Other, net

88,894


(157
)

1,800


90,537

Income (loss) from continuing operations before income tax

129,284


(1,800
)

1,701


129,185

Deferred income tax expense

(45,778
)

—


—


(45,778
)
Income (loss) from continuing operations

83,506


(1,800
)

1,701


83,407

Net income (loss)

$
83,506


$
(1,800
)

$
1,701


$
83,407




29
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)

Condensed consolidating statement of operations
For the three months ended September 30, 2013
(Unaudited)
(in thousands)
 
Laredo
 
Laredo Midstream
 
Intercompany
eliminations
 
Consolidated
company
Total operating revenues
 
$
170,907


$
2,176


$
(2,243
)

$
170,840

Total operating costs and expenses
 
114,754


909


(2,243
)

113,420

Income from operations
 
56,153


1,267


—


57,420

Interest expense, net
 
(24,870
)

—


—


(24,870
)
Other, net
 
(8,869
)

4,606


(6,422
)

(10,685
)
Income from continuing operations before income tax
 
22,414


5,873


(6,422
)

21,865

Deferred income tax expense
 
(10,048
)

—


—


(10,048
)
Income from continuing operations
 
12,366


5,873


(6,422
)

11,817

Income from discontinued operations, net of tax
 
177


549


—


726

Net income
 
$
12,543


$
6,422


$
(6,422
)

$
12,543


Condensed consolidating statement of operations
For the nine months ended September 30, 2014
(Unaudited)

(in thousands)

Laredo

Laredo Midstream

Intercompany
eliminations

Consolidated
company
Total operating revenues

$
556,054


$
5,066


$
(4,525
)

$
556,595

Total operating costs and expenses

358,168


9,090


(4,426
)

362,832

Income (loss) from operations

197,886


(4,024
)

(99
)

193,763

Interest expense, net

(89,882
)

—


—


(89,882
)
Other, net

(8,099
)

(234
)

4,258


(4,075
)
Income (loss) from continuing operations before income tax

99,905


(4,258
)

4,159


99,806

Deferred income tax expense

(35,511
)

—


—


(35,511
)
Income (loss) from continuing operations

64,394


(4,258
)

4,159


64,295

Net income (loss)

$
64,394


$
(4,258
)

$
4,159


$
64,295




30
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)

Condensed consolidating statement of operations
For the nine months ended September 30, 2013
(Unaudited)

(in thousands)
 
Laredo
 
Laredo Midstream
 
Intercompany
eliminations
 
Consolidated
company
Total operating revenues
 
$
511,872


$
7,540


$
(7,571
)

$
511,841

Total operating costs and expenses
 
357,613


2,460


(7,571
)

352,502

Income from operations
 
154,259


5,080


—


159,339

Interest expense, net
 
(76,135
)

—


—


(76,135
)
Other, net
 
4,220


4,493


(12,464
)

(3,751
)
Income from continuing operations before income tax
 
82,344


9,573


(12,464
)

79,453

Deferred income tax expense
 
(31,205
)

—


—


(31,205
)
Income from continuing operations
 
51,139


9,573


(12,464
)

48,248

Income (loss) from discontinued operations, net of tax
 
(1,375
)

2,891


—


1,516

Net income
 
$
49,764


$
12,464


$
(12,464
)

$
49,764


Condensed consolidating statement of cash flows
For the nine months ended September 30, 2014
(Unaudited)
(in thousands)
 
Laredo
 
Laredo Midstream
 
Intercompany
eliminations
 
Consolidated
company
Net cash flows provided by (used in) operating activities
 
$
373,834

 
$
(1,756
)
 
$
4,258

 
$
376,336

Change in investments between affiliates
 
(79,356
)
 
83,614

 
(4,258
)
 
—

Capital expenditures and other
 
(951,890
)
 
(81,858
)
 
—

 
(1,033,748
)
Net cash flows provided by financing activities
 
515,019

 
—

 
—

 
515,019

Net decrease in cash and cash equivalents
 
(142,393
)
 
—

 
—

 
(142,393
)
Cash and cash equivalents at beginning of period
 
198,153

 
—

 
—

 
198,153

Cash and cash equivalents at end of period
 
$
55,760

 
$
—

 
$
—

 
$
55,760

 
Condensed consolidating statement of cash flows
For the nine months ended September 30, 2013
(Unaudited)
(in thousands)
 
Laredo
 
Laredo Midstream
 
Intercompany
eliminations
 
Consolidated
company
Net cash flows provided by operating activities
 
$
276,886

 
$
11,016

 
$
(12,464
)
 
$
275,438

Change in investments between affiliates
 
28,636

 
(41,100
)
 
12,464

 
—

Capital expenditures and other
 
(205,042
)
 
30,084

 
—

 
(174,958
)
Net cash flows provided by financing activities
 
131,566

 
—

 
—

 
131,566

Net increase in cash and cash equivalents
 
232,046

 
—

 
—

 
232,046

Cash and cash equivalents at beginning of period
 
33,224

 
—

 
—

 
33,224

Cash and cash equivalents at end of period
 
$
265,270

 
$
—

 
$
—

 
$
265,270



31
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)

O—Subsequent events
1.    Senior Secured Credit Facility
On October 27, 2014, the Senior Secured Credit Facility's borrowing base and aggregate elected commitment amounts increased to $1.15 billion and $900.0 million, respectively.
On each of October 7 and 15 and November 3, 2014, the Company borrowed $25.0 million on the Senior Secured Credit Facility. The outstanding balance under the Senior Secured Credit Facility was $150.0 million at November 4, 2014.
2. Medallion capital call
On October 2, 2014, the Company received a capital call from Medallion totaling $17.6 million, which represents Laredo Midstream's proportionate contributions for the Wolfcamp Connector and extension construction project costs.
3. Potential transaction
As the Company pursues reserves and production growth in the Permian Basin, it continually considers which financing alternatives, including debt and equity capital resources, joint ventures and asset sales, are available to meet additional or accelerated future planned capital expenditures. Currently, the Company is evaluating various sources and has engaged an adviser to assist with structuring a potential transaction with a portion of its northern Permian-Garden City proved and unproved oil and natural gas properties. These properties will not be presented as held for sale pursuant to the rules governing full cost accounting for oil and natural gas properties. There can be no assurance that any transaction will be completed.
4. Formation of Garden City Minerals, LLC
On October 24, 2014, the Company formed Garden City Minerals, LLC (“GCM”), a Delaware limited liability company, for the purpose of holding its mineral interests. GCM is wholly owned by Laredo and will fully and unconditionally guarantee the 2019 Notes, the January 2022 Notes, the May 2022 Notes and the Senior Secured Credit Facility.
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 September 30,

Nine months ended September 30,
(in thousands)
 
2014

2013

2014

2013
Property acquisition costs:
 
 

 
 

 
 

 
—

Proved
 
$
—

 
$
9,652


$
3,873


$
9,652

Unproved
 
—


27,087


9,925


27,087

Exploration(1)
 
200,711


8,317


217,353


29,245

Development costs(2)
 
325,118


148,877


733,671


471,609

Total costs incurred
 
$
525,829


$
193,933


$
964,822


$
537,593

____________________________________________________________________________
(1)
The Company acquired significant leasehold interests during the three months ended September 30, 2014.
(2)
The costs incurred for oil and natural gas development activities include $1.6 million and $0.7 million in asset retirement obligations for the three months ended September 30, 2014 and 2013, respectively, and $3.1 million and $2.0 million for the nine months ended September 30, 2014 and 2013, respectively.


32

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, refer to Laredo Petroleum, Inc. together with Laredo Midstream and (ii) when used for historical periods from December 19, 2011 to December 30, 2013, 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 in the Mid-Continent region of the United States (the "Anadarko Basin").
Our financial and operating performance for the three months ended September 30, 2014 included the following:
•
Permian oil and natural gas sales of $199.5 million, compared to $159.4 million for the three months ended September 30, 2013;
•
Permian average daily sales volumes of 32,970 BOE/D, compared to 24,332 BOE/D for the three months ended September 30, 2013; and
•
Adjusted EBITDA (a non-GAAP financial measure) of $142.0 million, compared to $119.6 million for the three months ended September 30, 2013.
Our financial and operating performance for the nine months ended September 30, 2014 included the following:
•
Permian oil and natural gas sales of $555.6 million, compared to $450.3 million for the nine months ended September 30, 2013;
•
Permian average daily sales volumes of 29,577 BOE/D, compared to 24,955 BOE/D for the nine months ended September 30, 2013; and
•
Adjusted EBITDA (a non-GAAP financial measure) of $447.3 million, compared to $360.8 million for the nine months ended September 30, 2013.
Recent developments
Potential transaction
As we pursue reserves and production growth in the Permian Basin, we continually consider which financing alternatives, including debt and equity capital resources, joint ventures and asset sales, are available to meet additional or accelerated future planned capital expenditures. Currently, we are evaluating various sources and have engaged an adviser to assist with structuring a potential transaction with a portion of our northern Permian-Garden City proved and unproved oil and natural gas properties. These properties will not be presented as held for sale pursuant to the rules governing full cost accounting for oil and natural gas properties. There can be no assurance that any transaction will be completed.
Senior Secured Credit Facility
On October 27, 2014, the Senior Secured Credit Facility's borrowing base and aggregate elected commitment amounts were increased to $1.15 billion and $900.0 million, respectively.
Formation of Garden City Minerals, LLC
On October 24, 2014, we formed Garden City Minerals, LLC (“GCM”), a Delaware limited liability company, for the purpose of holding our mineral interests. GCM is wholly owned by Laredo and will fully and unconditionally guarantee the 2019 Notes, the January 2022 Notes, the May 2022 Notes and the Senior Secured Credit Facility.

33

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 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 September 30, 2014, we had assembled 207,729 net acres in the Permian Basin of which 154,908 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 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 September 30, 2014 and September 30, 2013 used to value our reserves were $95.56 per Bbl for oil and $4.16 per MMBtu for natural gas, and $91.79 per Bbl for oil and $3.46 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 primarily 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 September 30, 2014, our revenues were comprised of sales of 78% oil and 22% liquids-rich natural gas. For the nine months ended September 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.

34

Results of operations
Three and nine months ended September 30, 2014 as compared to the three and nine months ended September 30, 2013
Sales volume, revenue and pricing
The following table sets forth information regarding sales volume, revenue and average sales prices from continuing operations per BOE sold, for the periods presented:
 
 
Three months ended September 30,

Nine months ended September 30,
 
 
2014

2013

2014

2013
Sales volumes:
 
 


 

 
 

 
 

Oil (MBbl)
 
1,778


1,282


4,712


4,127

Natural gas (MMcf)(1)
 
7,533


7,965


20,176


29,025

Oil equivalents (MBOE)(2)(3)
 
3,033


2,609


8,074


8,964

Average daily sales volumes (BOE/D)(3)
 
32,970


28,361


29,577


32,836

% Oil
 
59
%

49
%

58
%

46
%
Revenues (in thousands):
 



 
 
 
 
 
Oil
 
$
155,829


$
128,966

 
$
429,175

 
$
372,617

Natural gas
 
43,661


41,874

 
126,401

 
138,896

Midstream service revenue
 
751


—

 
1,019

 
328

Total revenues
 
$
200,241


$
170,840

 
$
556,595

 
$
511,841

Average sales prices:
 



 
 
 
 
 
Oil, realized ($/Bbl)(4)
 
$
87.65


$
100.62


$
91.09


$
90.30

Natural gas, realized ($/Mcf)(4)
 
$
5.80


$
5.26


$
6.26


$
4.79

Average price, realized ($/BOE)(4)
 
$
65.78


$
65.48


$
68.80


$
57.08

Oil, hedged ($/Bbl)(5)
 
$
88.86


$
94.63


$
89.73


$
88.05

Natural gas, hedged ($/Mcf)(5)
 
$
5.87


$
5.35


$
6.24


$
4.84

Average price, hedged ($/BOE)(5)
 
$
66.66


$
62.82


$
67.95


$
56.21

________________________________________________________________________
(1)
Excludes gas produced and consumed in operations of 67 MMcf and 83 MMcf for the three and nine months ended September 30, 2014, respectively. There were no comparable amounts for the three and nine months ended September 30, 2013.
(2)
Bbl equivalents are calculated using a conversion rate of six Mcf per one Bbl.
(3)
The volumes presented are based on actual results and are not calculated using the rounded numbers presented in the table above.
(4)
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.
(5)
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.
    

35

The following table presents cash settlements received (paid) 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 September 30,

Nine months ended September 30,
(in thousands)
 
2014

2013

2014

2013
Cash settlements received (paid) for matured commodity derivatives:
 





 
 
 
 
Oil
 
$
3,745


$
(5,577
)
 
$
(1,486
)
 
$
(3,375
)
Natural gas
 
786


1,602

 
166

 
4,263

Total
 
$
4,531


$
(3,975
)
 
$
(1,320
)
 
$
888

Premiums paid attributable to contracts that matured during the respective period:
 





 
 
 
 
Oil
 
$
1,590


$
2,094

 
$
4,908

 
$
5,876

Natural gas
 
230


831

 
691

 
2,805

Total
 
$
1,820


$
2,925

 
$
5,599

 
$
8,681

 
Changes in prices and volumes caused the following changes to our oil and natural gas revenue between the three months ended September 30, 2014 and 2013:
(in thousands)
 
Oil
 
Natural gas
 
Total net dollar
effect of change
2013 Revenue
 
$
128,966

 
$
41,874

 
$
170,840

Effect of changes in price
 
(23,059
)
 
4,067

 
(18,992
)
Effect of changes in volumes
 
49,924

 
(2,275
)
 
47,649

Other
 
(2
)
 
(5
)
 
(7
)
2014 Revenue
 
$
155,829

 
$
43,661

 
$
199,490

 
The changes in prices and volumes shown in the table above caused the following changes to our oil and natural gas revenue between the nine months ended September 30, 2014 and 2013:
(in thousands)
 
Oil
 
Natural gas
 
Total net dollar
effect of change
2013 Revenue
 
$
372,617

 
$
138,896

 
$
511,513

Effect of changes in price
 
3,722

 
29,658

 
33,380

Effect of changes in volumes
 
52,837

 
(42,387
)
 
10,450

Other
 
(1
)
 
234

 
233

2014 Revenue
 
$
429,175

 
$
126,401

 
$
555,576

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 $28.7 million, or 17%, for the three months ended September 30, 2014 as compared to the three months ended September 30, 2013, is mainly due to a 39% increase in oil production and a 10% increase in natural gas prices realized. The increases in oil volumes and in natural gas prices were offset in part by a 13% decrease in oil prices realized, and due to the Anadarko Basin Sale, a 5% decrease in natural gas production.
The total increase in oil and natural gas revenues of $44.1 million, or 9%, for the nine months ended September 30, 2014 as compared to the nine months ended September 30, 2013, is mainly due to a 31% increase in natural gas prices realized and a 14% increase in oil production. The increases in natural gas prices and in oil volumes were offset by a 30% decrease in natural gas production due to the Anadarko Basin Sale.

36


Costs and expenses
The following table sets forth information regarding costs and expenses from continuing operations and average costs per BOE sold for the periods presented:
 
 
Three months ended September 30,

Nine months ended September 30,
(in thousands except for per BOE sold data)
 
2014

2013

2014

2013
Costs and expenses:
 
 

 
 

 
 

 
 

Lease operating expenses
 
$
25,165

 
$
19,565

 
$
67,129

 
$
64,192

Midstream service expense
 
1,225

 
1,090

 
3,596

 
2,569

Production and ad valorem taxes
 
12,550

 
11,723

 
38,160

 
32,890

Natural gas volume commitment - affiliates
 
675

 
305

 
1,779

 
444

General and administrative(1)
 
27,078

 
24,405

 
84,284

 
64,534

Accretion of asset retirement obligations
 
442

 
350

 
1,279

 
1,154

Depletion, depreciation and amortization
 
63,942

 
55,982

 
166,605

 
186,719

Total costs and expenses
 
$
131,077

 
$
113,420

 
$
362,832

 
$
352,502

Average costs per BOE sold:






 
 
 
 
Lease operating expenses

$
8.30


$
7.50


$
8.31


$
7.16

Midstream service expense
 
0.40

 
0.42

 
0.45

 
0.29

Production and ad valorem taxes

4.14


4.49


4.73


3.67

General and administrative(1)
 
8.93


9.35


10.44


7.20

Depletion, depreciation and amortization
 
21.08


21.46


20.63


20.83

Total
 
$
42.85


$
43.22


$
44.56


$
39.15

________________________________________________________________________
(1)
General and administrative includes non-cash stock-based compensation, net of amount capitalized, of $6.2 million and $5.9 million for the three months ended September 30, 2014 and 2013, respectively, and $16.9 million and $13.6 million for the nine months ended September 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 sold of $6.89 and $7.10 for the three months ended September 30, 2014 and 2013, respectively, and $8.34 and $5.69 for the nine months ended September 30, 2014 and 2013, respectively.
Lease operating expenses. For the three months ended September 30, 2014, lease operating expenses, which include workover expenses, increased by $5.6 million, or 29%, compared to the same period in 2013. Production increased 16% for the three months ended September 30, 2014, compared to the same period in 2013. For the nine months ended September 30, 2014, lease operating expenses, which include workover expenses, increased by $2.9 million, or 5%, compared to the same period in 2013. Production decreased 10% for the nine months ended September 30, 2014 compared to the same periods in 2013, primarily as a result of the Anadarko Basin Sale. On a per-BOE basis, lease operating expenses increased in total to $8.30 and $8.31 per BOE sold for the three and nine months ended September 30, 2014, from $7.50 and $7.16 per BOE sold for the same periods in 2013. The increases were mainly due to (i) higher average lease operating expenses per-BOE on our higher oil-weighted production, (ii) an increase in well count and (iii) higher well service and workover expenses.
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 centralized compression infrastructure. These expenses increased by $0.1 million, or 12%, and $1.0 million, or 40%, for the three and nine months ended September 30, 2014, respectively, compared to the same periods in 2013, due to the expanded midstream service component of our business.
Production and ad valorem taxes. Production and ad valorem taxes increased by $0.8 million, or 7%, and $5.3 million, or 16%, for the three and nine months ended September 30, 2014, respectively, compared to the same periods in 2013. Production taxes increased by $2.0 million and $6.4 million for the three and nine months ended September 30, 2014, respectively, compared to the same periods in 2013. Production taxes are based on and increase in proportion to our oil and natural gas revenue. Ad valorem taxes decreased by $1.2 million and $1.1 million during the three and nine months ended September 30, 2014, respectively, compared to the same periods in 2013, primarily as a result of the Anadarko Basin Sale. The ad valorem tax decreases were partially offset by the ad valorem tax expense incurred for new wells drilled during the nine-month period ended September 30, 2014.

37


General and administrative ("G&A"). G&A expense, excluding stock-based compensation, increased by $2.4 million, or 13%, and $16.4 million, or 32%, for the three and nine months ended September 30, 2014, respectively, compared to the same 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 by $3.5 million and $9.0 million for the three and nine months ended September 30, 2014, respectively, compared to the same periods in 2013. The increase during the nine months ended September 30, 2014 was offset by increased capitalization of salary and benefits of $1.0 million compared to the same period in 2013. Capitalization of salary and benefits remained consistent for the three months ended September 30, 2014 compared to 2013. Professional fees increased by $2.1 million and $7.1 million for the three and nine months ended September 30, 2014, respectively, compared to the same periods in 2013 mainly due to fees paid to a consulting company engaged in 2014 to assist us with the optimization of our development operations. We also pledged a $3.0 million charitable contribution during the nine months ended September 30, 2014, which will be paid in annual payments through 2024.
Stock-based compensation increased by $1.6 million, or 27%, and $6.8 million, or 50%, for the three and nine months ended September 30, 2014, respectively, compared to the same periods in 2013, mainly due to the issuance of 1,209,420 restricted stock awards at a weighted-average grant price of $25.81 per share and 336,140 non-qualified restricted stock options to new and existing employees and non-employee directors in the nine months ended September 30, 2014 compared to the issuance of 1,444,911 restricted stock awards at a weighted-average grant price of $17.95 per share and 1,018,849 non-qualified restricted stock options to new and existing employees and non-employee directors in the same period in 2013. Additionally, during the nine months ended September 30, 2014, we issued 271,667 Performance Share Awards to management and the associated expense amounted to $0.6 million and $1.5 million for the three and nine months ended September 30, 2014, respectively. No comparable awards were issued during the nine months ended September 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 and exploration of our oil and natural gas properties into the full-cost pool in 2014. Capitalized stock-based compensation amounted to $1.2 million and $3.4 million for the three and nine months ended September 30, 2014, respectively. No amounts were capitalized during the nine months ended September 30, 2013.
The fair values of the restricted stock awards issued during 2014 and 2013 were 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 values of our non-qualified restricted stock options were 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 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 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.
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 $0.4 million and increased by $0.8 million for the three and nine months ended September 30, 2014, respectively, compared to increases of $2.8 million and $5.0 million for the same periods in 2013, 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.
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 September 30,

Nine months ended September 30,
(in thousands except for per BOE sold data)
 
2014

2013

2014

2013
Depletion of proved oil and natural gas properties
 
$
61,429

 
$
54,358

 
$
160,126

 
$
182,489

Depreciation of midstream service assets
 
1,207

 
574

 
2,899

 
1,552

Depreciation and amortization of fixed assets
 
1,306

 
1,050

 
3,580

 
2,678

Total DD&A
 
$
63,942

 
$
55,982

 
$
166,605

 
$
186,719

DD&A per BOE sold
 
$
21.08

 
$
21.46

 
$
20.63

 
$
20.83

DD&A increased by $8.0 million, or 14%, and decreased by $20.1 million, or 11%, for the three and nine months ended September 30, 2014, respectively, as compared to the same periods in 2013. The increase for the three months ended

38


September 30, 2014 compared to the same period in 2013 is mainly due to (i) increased net book value on new reserves added, (ii) higher total production levels, (iii) increased capitalized costs for new wells completed in the third quarter of 2014 and (iv) the impact of the Anadarko Basin Sale to prior-year depletion. The decrease for the nine months ended September 30, 2014 compared to the same period in 2013 is mainly the 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 September 30,

Nine months ended September 30,
(in thousands)
 
2014

2013

2014

2013
Non-operating income (expense):
 
 

 
 

 
 

 
 

Gain (loss) on derivatives:
 
 

 
 

 
 

 
 

Commodity derivatives, net
 
$
92,790

 
$
(9,830
)
 
$
(1,447
)
 
$
(2,709
)
Interest rate derivatives, net
 
—

 
(8
)
 
—

 
(23
)
Income (loss) from equity method investee
 
(61
)
 
48

 
(86
)
 
(65
)
Interest expense
 
(30,549
)
 
(24,929
)
 
(90,192
)
 
(76,221
)
Interest and other income
 
33

 
59

 
310

 
86

Write-off of deferred loan costs
 
—

 
(1,502
)
 
(124
)
 
(1,502
)
Gain (loss) on disposal of assets, net
 
(2,192
)
 
607

 
(2,418
)
 
548

Non-operating income (expense), net
 
$
60,021

 
$
(35,555
)
 
$
(93,957
)
 
$
(79,886
)
Commodity derivatives. Net loss on commodity derivatives for the three months ended September 30, 2013 became a net gain on commodity derivatives for the three months ended September 30, 2014, which is a change of $102.6 million. Net loss on commodity derivatives decreased $1.3 million for the nine months ended September 30, 2014 compared to the same period in 2013. Net cash settlements received on matured commodity derivatives were $4.5 million and net cash settlements paid were $1.3 million for the three and nine months ended September 30, 2014, respectively, compared to net cash settlements paid on matured commodity derivatives of $4.0 million and net cash settlements received of $0.9 million for the same periods in 2013. These changes between periods resulted in an increase in cash flow of $8.5 million for the three months ended September 30, 2014 and a decrease in cash flow of $2.2 million for the nine months ended September 30, 2014, compared to the respective prior-year period. These changes are based on the cash settlement prices of our commodity derivatives compared to the prices specified in those contracts. Additionally, during the nine months ended September 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 and the related physical contract. During the three and nine months ended September 30, 2013, we received net proceeds from the early terminations of derivatives of $5.4 million as a result of unwinding nine natural gas commodity contracts due to the Anadarko Basin Sale.
The change in fair value of commodity derivatives still held was an increase of $94.1 million and a decrease of $73.2 million for the three and nine months ended September 30, 2014, respectively, compared to the same periods in 2013. The increase for the three months ended September 30, 2014 compared to the same period in 2013 is the 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. The decrease for the nine months ended September 30, 2014 compared to the same period in 2013 is mainly the result of the early settlement in February 2014 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.
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 $5.6 million, or 23%, and by $14.0 million, or 18%, for the three and nine months ended September 30, 2014, respectively, compared to the same periods in 2013. The increase is primarily due to the issuance of the January 2022 Notes in January 2014, which was partially offset by the reduction in amount outstanding under the Senior Secured Credit Facility and the related commitment fees on the unused portion of the banks' commitment on the Senior Secured Credit Facility.

39


The table below shows the change in the significant components of interest expense for the three and nine months ended September 30, 2014 as compared to the same periods in 2013:
(in thousands)
 
Three months ended
September 30, 2014
compared to 2013
 
Nine months ended
September 30, 2014
compared to 2013
Changes in interest expense:
 
 

 
 

January 2022 Notes
 
$
6,328

 
$
17,508

Senior Secured Credit Facility, net of capitalized interest
 
(608
)
 
(3,250
)
Other
 
(100
)
 
(287
)
Total change in interest expense
 
$
5,620

 
$
13,971

Disposal of assets. Net gain on disposal of assets in the prior year became a net loss on disposal of assets in the current year. This change of $2.8 million and $3.0 million for the three and nine months ended September 30, 2014, respectively, compared to the same periods in 2013, is a result of losses related to sales of inventory and a write-off of abandoned internally developed software during 2014, compared to a gain recorded in 2013 for the sale of pipeline assets and various other property and equipment associated with the Anadarko Basin Sale.
Income tax expense. The fluctuations in income from continuing operations before income taxes is shown in the table below:
 
 
Three months ended September 30,

Nine months ended September 30,
(in thousands)
 
2014

2013

2014

2013
Income from continuing operations before income taxes
 
$
129,185

 
$
21,865

 
$
99,806

 
$
79,453

Income tax expense
 
(45,778
)
 
(10,048
)
 
(35,511
)
 
(31,205
)
Income from continuing operations
 
$
83,407

 
$
11,817

 
$
64,295

 
$
48,248

Effective tax rate
 
35
%
 
46
%
 
36
%
 
39
%
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. 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 nine months ended September 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 nine months ended September 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 a result of these differences in book compensation cost and related tax deduction, the tax impact of these shortfalls decreased by $0.1 million and by $0.4 million for the three and nine months ended September 30, 2014, respectively, compared to the same periods in 2013.
As of September 30, 2014 and 2013, we did not have any eligible windfall tax benefits to offset future shortfalls as no excess tax benefits had been recognized, and therefore the tax impact of these shortfalls is included in income tax expense

40


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 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. As we pursue reserves and production growth in the Permian Basin, we continually consider which financing alternatives, including debt and equity capital resources, joint ventures and asset sales, are available to meet our future planned or accelerated capital expenditures. Our primary uses of capital have been for the acquisition, exploration and development of oil and natural gas properties and Laredo Midstream's infrastructure development and investments in Medallion, our equity method investee.
As of September 30, 2014, we had $75.0 million outstanding under our Senior Secured Credit Facility and $1.5 billion in senior unsecured notes. We had $750.0 million available for borrowings under our Senior Secured Credit Facility and $55.8 million in cash on hand for total available liquidity of $805.8 million as of September 30, 2014.
On October 27, 2014, our aggregate elected commitment increased to $900.0 million and our borrowing base increased to $1.15 billion on our Senior Secured Credit Facility. Subsequent to September 30, 2014, we borrowed an additional $75.0 million on our Senior Secured Credit Facility. As of November 4, 2014 we had $1.65 billion in debt outstanding, $750.0 million available for borrowings under our Senior Secured Credit Facility and $10.9 million in cash on hand for total available liquidity of $760.9 million.
We are in the process of planning our 2015 capital program, which we currently expect will be less than our 2014 capital program. We believe cash on hand, cash flows from operations and the availability on our Senior Secured Credit Facility provide us with the ability to implement the remainder of our 2014 planned capital program and our contemplated 2015 capital program.
Our commodity derivative positions will help us stabilize a portion of our expected cash flows from operations 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:
 
 
Nine months ended September 30,
(in thousands)
 
2014
 
2013
Net cash provided by operating activities
 
$
376,336

 
$
275,438

Net cash used in investing activities
 
(1,033,748
)
 
(174,958
)
Net cash provided by financing activities
 
515,019

 
131,566

Net (decrease) increase in cash and cash equivalents
 
$
(142,393
)
 
$
232,046

For the nine months ended September 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 $376.3 million and $275.4 million for the nine months ended September 30, 2014 and 2013, respectively. The increase of $100.9 million was largely due to an increase of $71.3 million net proceeds received for early terminations of commodity derivative contracts and increases in changes from working capital, other noncurrent liabilities, and the fair value of performance unit awards of $28.6 million.
Our operating cash flows are sensitive to a number of variables, the most significant of which are production levels and the volatility of oil and natural gas 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

41


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
Cash flows used in investing activities were $1.0 billion and $175.0 million for the nine months ended September 30, 2014 and 2013, respectively. The increase of $858.8 million is mainly attributable to (i) increased capital expenditures for oil and natural gas properties and midstream service assets during the nine months ended September 30, 2014, (ii) significant leasehold acquisitions during the nine months ended September 30, 2014, which are included in the "Oil and natural gas properties" line item below, and (iii) proceeds from our Anadarko Basin Sale in the prior period, which offset the total cash flows used in investing activities for the nine months ended September 30, 2013.
Our cash used in investing activities for the periods presented are summarized in the table below:
 
 
Nine months ended September 30,
(in thousands)
 
2014
 
2013
Capital expenditures:
 
 
 
 
Acquisition of oil and natural gas properties
 
$
(6,493
)
 
$
(33,710
)
Acquisition of mineral interests
 
(7,305
)
 
—

Oil and natural gas properties
 
(925,121
)
 
(538,395
)
Midstream service assets
 
(45,263
)
 
(15,394
)
Other fixed assets
 
(13,612
)
 
(13,874
)
Investment in equity method investee
 
(37,581
)
 
(3,287
)
Proceeds from dispositions of capital assets, net of costs
 
1,627

 
429,702

Net cash used in investing activities
 
$
(1,033,748
)
 
$
(174,958
)
Capital expenditure budget
Our board of directors approved a capital expenditure budget of approximately $1.1 billion for calendar year 2014, excluding acquisitions. Additionally, our board of directors approved leasehold interest transactions of approximately $0.2 billion in 2014. We do not have a specific acquisition budget since the timing and size of acquisitions (if any) 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. Subject to financing alternatives, we may also increase our capital expenditures significantly to take advantage of opportunities we consider to be attractive. We consistently monitor and may adjust our projected capital expenditures in response to success or lack of success in drilling activities, changes in prices, availability of financing, 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
Our cash flows provided by financing activities were $515.0 million and $131.6 million for the nine months ended September 30, 2014 and 2013, respectively. For the nine months ended September 30, 2014, our primary source of cash provided by financing activities were our issuance of the January 2022 Notes and borrowings on our Senior Secured Credit Facility. During the nine months ended September 30, 2013, our primary sources of cash provided by financing activities were proceeds from the issuance of common stock and borrowings on the Senior Secured Credit Facility. Additionally, during the nine months ended September 30, 2013, we paid the outstanding balance of the Senior Secured Credit Facility with a portion of the proceeds from the Anadarko Basin Sale.
    

42


Our cash provided by financing activities for the periods presented are summarized in the table below:
 
 
Nine months ended September 30,
(in thousands)
 
2014
 
2013
Cash flows from financing activities:
 
 
 
 
Borrowings on Senior Secured Credit Facility
 
$
75,000

 
$
230,000

Payments on Senior Secured Credit Facility
 
—

 
(395,000
)
Issuance of January 2022 Notes
 
450,000

 
—

Proceeds from issuance of common stock, net of offering costs
 
—

 
298,104

Purchase of treasury stock
 
(4,075
)
 
(1,478
)
Proceeds from exercise of employee stock options
 
1,885

 
654

Payments for loan costs
 
(7,791
)
 
(714
)
Net cash provided by financing activities
 
$
515,019

 
$
131,566

Debt
As of September 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 September 30, 2014, our Senior Secured Credit Facility, which matures November 4, 2018, had a maximum credit amount of $2.0 billion, a borrowing base of $1.0 billion, an aggregate elected commitment amount of $825.0 million and $75.0 million outstanding.
Principal amounts borrowed under the Senior Secured Credit Facility are payable on the final maturity date with such borrowings bearing interest that is payable, at our election, either on the last day of each fiscal quarter at an Adjusted Base Rate or at the end of one-, two-, three-, six- or, to the extent available, 12-month interest periods (and in the case of six- and 12-month interest periods, every three months prior to the end of such interest period) at an Adjusted London Interbank Offered Rate, in each case, plus an applicable margin based on the ratio of the outstanding amount on the Senior Secured Credit Facility to the elected commitment. We are also required to pay an annual commitment fee on the unused portion of the bank's commitment of 0.375% to 0.5%.
Our Senior Secured Credit Facility is secured by a first-priority lien on 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 September 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

43


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 November 4, 2014, we had a total of $1.5 billion of senior unsecured notes outstanding and $150.0 million outstanding on the Senior Secured Credit Facility.
Obligations and commitments
As of September 30, 2014, our contractual obligations included our 2019 Notes, January 2022 Notes, May 2022 Notes, Senior Secured Credit Facility, drilling contract commitments, derivatives, performance unit liability awards, asset retirement obligations, office and equipment leases and capital contribution commitments to our equity method investee. From December 31, 2013 to September 30, 2014, the material changes in our contractual obligations included (i) an increase of $639.8 million in principal and interest due to the January 2022 Notes offering, (ii) an increase of $75.0 million outstanding on our Senior Secured Credit Facility, (iii) a decrease in our outstanding capital contribution commitment to our equity method investee due to a payment by us of $37.6 million towards the construction of a pipeline by MPC, offset by commitments to Medallion of $21.4 million for the construction of an extension pipeline and $3.5 million remaining for the construction of the Wolfcamp Connector, (iv) an increase of $18.8 million for drilling contract commitments (on contracts other than those on a well-by-well basis) and (v) an increase in future lease payments of $13.4 million related to office expansions.
Refer to Notes B, D, E, G, H, J and L to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our contractual obligations.
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 commodity 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.

44


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 from continuing and discontinued operations to Adjusted EBITDA:
 
 
Three months ended September 30,

Nine months ended September 30,
(in thousands)
 
2014

2013

2014

2013
Net income
 
$
83,407


$
12,543


$
64,295


$
49,764

Plus:
 






 


 

Interest expense
 
30,549


24,929


90,192


76,221

Depletion, depreciation and amortization
 
63,942


55,982


166,605


187,346

Write-off of deferred loan costs
 
—


1,502


124


1,502

Bad debt expense

—


653


—


653

(Gain) loss on disposal of assets, net

2,192


(607
)

2,418


(548
)
(Gain) loss on derivatives, net

(92,790
)

9,838


1,447


2,732

Cash settlements received (paid) for matured commodity derivatives, net

4,531


(3,975
)

(1,320
)

888

Cash settlements received for early terminations of commodity derivatives, net

—


5,366


76,660


5,366

Premiums paid for derivatives that matured during the period(1)
 
(1,820
)

(2,925
)

(5,599
)

(8,681
)
Non-cash stock-based compensation, net of amount capitalized
 
6,194


5,876


16,919


13,556

Deferred income tax expense
 
45,778


10,369


35,511


31,970

Adjusted EBITDA
 
$
141,983


$
119,551


$
447,252


$
360,769

______________________________________________________________________________
(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, (vi) asset retirement obligations, (vii) valuation of derivatives and deferred premiums, (viii) valuation of stock-based compensation and performance unit compensation and (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 nine months ended September 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

45


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 what impact this guidance will have on our consolidated financial statements upon adoption.

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. We 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 our 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. 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."


46


Item 3.    Quantitative and Qualitative Disclosures About Market Risk
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term "market risk," in our case, refers to the risk of loss arising from adverse changes in oil and natural gas prices and in interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for hedging purposes, rather than for speculative trading.
Commodity price exposure
Due to the inherent volatility in oil 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 September 30, 2014 are as follows:
 
 
Remaining year
 2014
 
Year
 2015
 
Year
 2016
 
Year
2017
 
Total
Oil(1)
 
 
 
 
 
 

 
 
 
 

Total volume hedged with ceiling price (Bbl)
 
1,422,499

 
7,229,020

 
4,129,800

 
2,263,000

 
15,044,319

Weighted-average ceiling price ($/Bbl)
 
$
100.38

 
$
95.51

 
$
90.36

 
$
100.00

 
$
95.23

Total volume hedged with floor price (Bbl)
 
1,557,499

 
7,685,020

 
4,129,800

 
2,263,000

 
15,635,319

Weighted-average floor price ($/Bbl)
 
$
89.45

 
$
80.99

 
$
81.84

 
$
80.00

 
$
81.91

Natural gas(2)
 
 
 
 
 
 
 
 
 
 
Total volume hedged with ceiling price (MMBtu)
 
5,482,000

 
28,600,000

 
18,666,000

 
—

 
52,748,000

Weighted-average ceiling price ($/MMBtu)
 
$
5.14

 
$
5.96

 
$
5.60

 
$
—

 
$
5.75

Total volume hedged with floor price (MMBtu)
 
5,482,000

 
28,600,000


18,666,000

 
—

 
52,748,000

Weighted-average floor price ($/MMBtu)
 
$
3.66

 
$
3.00

 
$
3.00

 
$
—

 
$
3.07

Oil basis(3)
 
 
 
 
 
 
 
 
 
 
Total volume hedged (Bbl)
 
552,000

 
—

 
—

 
—

 
552,000

Weighted-average price ($/Bbl)
 
$
(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 West Texas Intermediate NYMEX Light Sweet Crude Oil Futures Contract for each NYMEX Trading Day during each month. Weighted-average prices include the Argus Midland and the 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 Argus Midland and the 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 September 30, 2014, a 10% change in the forward curves associated with our commodity derivatives would have changed our net positions to the following amounts:
(in thousands)
 
10% Increase
 
10% Decrease
Commodity derivatives
 
$
(87,121
)
 
$
100,386

As of September 30, 2014 and December 31, 2013, the fair values of our open derivative contracts were $10.7 million and $82.1 million, respectively. Refer to Notes G and H of our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional disclosures regarding our derivatives.    

47


Interest rate risk
Our Senior Secured Credit Facility bears interest at a floating rate and, as of September 30, 2014, we had $75.0 million 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 $1.4 million), $450.0 million and $500.0 million outstanding, respectively, as of September 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
 
$
—

 
$
—

 
$
—

 
$
—

 
$
75.0

 
$
—

 
$
75.0

Average interest rate
 
—
%
 
—
%
 
—
%
 
—
%
 
1.69
%
 
—
%
 
1.69
%
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 ($72.4 million as of September 30, 2014) which we market to energy marketing companies and refineries, (ii) joint interest receivables ($27.2 million as of September 30, 2014) and (iii) the receivables from derivatives ($16.8 million as of September 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 also are or were lenders in our Senior Secured Credit Facility. The terms of the ISDA Agreements provide the counterparties and us with rights of offset upon the occurrence of defined acts of default by either a counterparty or us to a derivative, whereby the party not in default may offset all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party.
Refer to Note I to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional disclosures regarding credit risk.

48


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 September 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 September 30, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

49


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 as well as the additional risk factor set forth below. Other than with respect to the added risk factor below, 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 and below 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.

New legislation and regulatory initiatives relating to water disposal wells could have a material adverse effect on our future business, financial condition, operating results and prospects.

In October 2014, the Texas Railroad Commission (the "RRC") adopted new regulations effective as of November 17, 2014 that require additional supporting documentation, including records from the U.S. Geological Survey regarding previous seismic events in the area, as part of applications for new disposal wells. The new regulations also clarify the RRC’s ability to modify, suspend or terminate a disposal well permit if scientific data indicates it is likely to contribute to seismic activity. In addition, new regulations have also been proposed in other states, including Oklahoma, which could also increase regulatory burdens on operators of disposal wells in such states. Because of the necessity to safely dispose of water produced during drilling and production activities, these regulations, or others like them, could have a material adverse effect on our future business, financial condition, operating results and prospects.

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
July 1, 2014 - July 31, 2014
 
13,255

 
$
29.57

 
—

 
—

August 1, 2014 - August 31, 2014
 
3,382

 
$
24.83

 
—

 
—

September 1, 2014 - September 30, 2014
 
1,951

 
$
22.50

 
—

 
—

Total
 
18,588

 
 
 
 
 
 
______________________________________________________________________________
(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.


50


Item 5.    Other Information

Disclosure pursuant to Section 13(r) of the Securities Exchange Act of 1934
Pursuant to Section 13(r) of the Exchange Act, we may be required to disclose in our annual and quarterly reports to the SEC, whether we or any of our "affiliates" knowingly engaged in certain activities, transactions or dealings relating to Iran or with certain individuals or entities targeted by U.S. economic sanctions. Disclosure is generally required even where the activities, transactions or dealings were conducted in compliance with applicable law. Because the SEC defines the term "affiliate" broadly, it includes any entity under common "control" with us (with the term "control" also being construed broadly by the SEC).
The description of the activities below has been provided to us by Warburg Pincus LLC ("WP"), affiliates of which: (i) beneficially own more than 10% of our outstanding common stock and/or are members of our board of directors and (ii) beneficially own more than 10% of the equity interests of, and have the right to designate members of the board of directors of, Endurance International Group ("EIG") and Santander Asset Management Investment Holdings Limited ("SAMIH"). EIG and SAMIH may therefore be deemed to be under common "control" with us; however, this statement is not meant to be an admission that common control exists.
The disclosure below relates solely to activities conducted by EIG and SAMIH and its non-U.S. affiliates that may be deemed to be under common "control" with us. The disclosure does not relate to any activities conducted by us or by WP and does not involve our or WP’s management. Neither WP nor Laredo has had any involvement in or control over the disclosed activities of EIG or SAMIH, and neither WP nor Laredo has independently verified or participated in the preparation of the disclosure. Neither WP nor Laredo is representing to the accuracy or completeness of the disclosure nor do WP or we undertake any obligation to correct or update it.
As to EIG:
We understand that EIG’s affiliates intend to disclose in their next annual or quarterly SEC report that on or around September 26, 2014, during a routine compliance scan of new and existing subscriber accounts, EIG or its affiliates discovered that Seyed Mahmoud Mohaddes ("Mohaddes") was named as the account contact for a subscriber account (the "Subscriber Account"). Previously, on July 2, 2013, before Mohaddes had been designated as a Specially Designated National ("SDN"), the billing information for the Subscriber Account was updated to include Mohaddes. On September 16, 2013, the Office of Foreign Assets Control ("OFAC") designated Mohaddes as a SDN, pursuant to 31 C.F.R. Part 560.304. EIG discovered Mohaddes when its routine compliance scan identified an attempt on or around September 26, 2014 to add Mohaddes, an SDN, as the account contact to the Subscriber Account. EIG blocked the Subscriber Account that day and reported the domain name registered to the Subscriber Account to OFAC as potentially the property of a SDN, subject to blocking pursuant to Executive Order 13599. Since September 16, 2013, when Mohaddes was added to the SDN list, charges in the total amount of $120.35 were made to the Subscriber Account for web hosting and domain privacy services. EIG ceased billing for the Subscriber Account. To date, EIG has not received any correspondence from OFAC regarding this matter.
On July 10, 2014, OFAC designated each of Stars Group Holding ("Stars"), and Teleserve Plus SAL ("Teleserve"), as SDNs under Executive Order 13224, and their property became subject to blocking pursuant to the Global Terrorism Sanctions Regulations, 31 C.F.R. Part 594. On July 15, 2014, as part of EIG’s compliance review processes, they discovered that the domain names associated with each of Stars and Teleserve (the "Stars/Teleserve Domain Names") were registered through EIG's platform. EIG immediately took steps to suspend and lock the Stars/Teleserve Domain Names to prevent them from being transferred or resolving to a website, and EIG promptly reported the Domain Names as potentially blocked property to OFAC. EIG did not generate any revenue from the Stars/Teleserve Domain Names since they were added to the SDN list on July 10, 2014. To date, EIG has not received any correspondence from OFAC regarding the matter.
On July 15, 2014 during a compliance scan of all domain names on one of its platforms, EIG identified the domain name Kahanetzadak.com (the "Domain Name"), which was listed as an AKA of the entity Kahane Chai which operates as the American Friends of the United Yeshiva and was designated as a SDN on November 2, 2001 pursuant to Executive Order 13224. Since the Domain Name was transferred into one of EIG’s reseller's customer's account, there was no direct financial transaction between EIG and the registered owner of the Domain Name. The Domain Name was suspended upon discovering it on their platform, and EIG will be reporting the Domain Name to OFAC as potentially the property of a SDN.
As to SAMIH:
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 classified by the U.S. under the Iranian Financial Sanctions Regulations and the Weapons of Mass Destruction Proliferators Sanctions Regulations ("NPWMD sanctions program"), holds two investment accounts with Santander Asset Management UK Limited ("Santander UK"). The accounts have remained frozen throughout 2013 and the nine months ended September 30, 2014. The investment returns are being automatically reinvested, and no

51


disbursements have been made to the customer. In the nine months ended September 30, 2014, the total revenue for the Santander Group in connection with the investment accounts was £190, while net profits were negligible relative to the overall profits of Banco Santander, S.A.
In addition, during the third quarter of 2014, Santander UK identified two additional customers. The first is a U.K. national designated by the U.S. under the NPWMD sanctions program who holds a business account, where no transaction have taken place. Such account is in the process of being closed. No revenue or profit has been generated. A second U.K. national designated by the U.S. for reasons of terrorism held a personal current account and a personal credit card account in the third quarter of 2014, both of which have now been closed. Although transactions have taken place on the current account during the reportable period, revenue and profits generated were negligible. No transactions have taken place on the credit card.


52


Item 6.    Exhibits

Exhibit
Number
 
Description
3.1

 
Amended and Restated Certificate of Incorporation of Laredo Petroleum Holdings, Inc. (incorporated by reference to Exhibit 3.1 of Laredo’s Current Report on Form 8-K (File No. 001-35380) filed on December 22, 2011).
 

 
 
3.2

 
Certificate of Ownership and Merger, dated as of December 30, 2013 (incorporated by reference to Exhibit 3.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on January 6, 2014).
 
 
 
3.3

 
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).
 

 
 
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.



53


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: November 6, 2014
By:
/s/ Randy A. Foutch
 
 
Randy A. Foutch
 
 
Chairman and Chief Executive Officer
 
 
(principal executive officer)
 
 
 
Date: November 6, 2014
By:
/s/ Richard C. Buterbaugh
 
 
Richard C. Buterbaugh
 
 
Executive Vice President and Chief Financial Officer
 
 
(principal financial officer)
 
 
 
 
By:
 
Date: November 6, 2014
By:
/s/ Michael T. Beyer
 
 
Michael T. Beyer
 
 
Vice President - Controller and Chief Accounting Officer
 
 
(principal accounting officer)
 
 
 
 
 
 

54


EXHIBIT INDEX
 
Exhibit
Number
 
Description
3.1

 
Amended and Restated Certificate of Incorporation of Laredo Petroleum Holdings, Inc. (incorporated by reference to Exhibit 3.1 of Laredo’s Current Report on Form 8-K (File No. 001-35380) filed on December 22, 2011).
 
 
 
3.2

 
Certificate of Ownership and Merger, dated as of December 30, 2013 (incorporated by reference to Exhibit 3.1 of Laredo's Current Report on Form 8-K (File No. 001-35380) filed on January 6, 2014).
 

 
 
3.3

 
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).
 
 
 
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.



55