10-Q
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, 2015
 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 2, 2015: 213,804,059


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 (the "Exchange Act"). These forward-looking statements include statements, projections and estimates concerning our operations, performance, business strategy, oil and natural gas reserves, drilling program capital expenditures, liquidity and capital resources, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, derivative activities and potential financing. Forward-looking statements are generally accompanied by words such as "estimate," "project," "predict," "believe," "expect," "anticipate," "potential," "could," "may," "will," "foresee," "plan," "goal," "should," "intend," "pursue," "target," "continue," "suggest" or the negative thereof or other variations thereof or other words that convey the uncertainty of future events or outcomes. Forward-looking statements are not guarantees of performance. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. Among the factors that significantly impact our business and could impact our business in the future are:
•
the volatility of oil, natural gas liquids ("NGL") and natural gas prices;
•
revisions to our reserve estimates as a result of changes in commodity prices;
•
impacts to our financial statements as a result of impairment write-downs;
•
changes in domestic and global production, supply and demand for oil, NGL and natural gas;
•
the continuation of restrictions on the export of domestic oil production and its potential to cause weakness in domestic pricing;
•
our ability to discover, estimate, develop and replace oil, NGL and natural gas reserves;
•
uncertainties about the estimates of our oil, NGL and natural gas reserves;
•
the potentially insufficient refining capacity in the U.S. Gulf Coast to refine all of the light sweet crude oil being produced in the U.S., which, coupled with the export limitations noted above and a continuing increase in light sweet crude oil production, could result in widening price discounts to world oil prices and potential shut-in of production due to lack of sufficient markets;
•
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 the demand for commodities, including oil, NGL and natural gas;
•
capital requirements for our operations and projects;
•
our ability to maintain the borrowing capacity under our Senior Secured Credit Facility (as defined below) or access other means of obtaining capital and liquidity;
•
our ability to generate sufficient cash to service our indebtedness, fund our capital requirements and generate future profits;
•
regulations that prohibit or restrict our ability to apply hydraulic fracturing to our oil and natural gas wells and to access and dispose of water used in these operations;
•
legislation or regulations that prohibit or restrict our ability to drill new allocation wells;
•
our ability to execute our strategies, including but not limited to our hedging strategies;
•
competition in the oil and natural gas industry;
•
changes in the regulatory environment and changes in international, legal, political, administrative or economic conditions;
•
drilling and operating risks, including risks related to hydraulic fracturing activities;
•
risks related to the geographic concentration of our assets;
•
the availability and costs of drilling and production equipment, labor and oil and natural gas processing and other services;
•
the availability of sufficient pipeline and transportation facilities and gathering and processing capacity;
•
our ability to comply with federal, state and local regulatory requirements;

iii

•
restrictions contained in our debt agreements, including our Senior Secured Credit Facility and the indentures governing our senior unsecured notes, as well as debt that could be incurred in the future, and;
•
our ability to recruit and retain the qualified personnel necessary to operate our business.
These forward-looking statements involve a number of risks and uncertainties that could cause actual results to differ materially from those suggested by the forward-looking statements. Forward-looking statements should, therefore, be considered in light of various factors, including those set forth under "Part I, Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations," "Part II, Item 1A. Risk Factors" and elsewhere in this Quarterly Report, under "Part II, Item 1A. Risk Factors" in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2015, 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, 2014 (the "2014 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, 2015

December 31, 2014
Assets
 
 

 
 

Current assets:
 
 

 
 

Cash and cash equivalents
 
$
76,403

 
$
29,321

Accounts receivable, net
 
100,675

 
126,929

Derivatives
 
184,157

 
194,601

Other current assets
 
14,207

 
14,402

Total current assets
 
375,442

 
365,253

Property and equipment:
 
 
 
 

Oil and natural gas properties, full cost method:
 
 
 
 

Evaluated properties
 
4,895,042

 
4,446,781

Unevaluated properties not being amortized
 
225,045

 
342,731

Midstream service assets
 
149,068

 
117,052

Other fixed assets
 
62,114

 
56,165

Total property and equipment
 
5,331,269

 
4,962,729

Less accumulated depletion, depreciation, amortization and impairment
 
(3,212,194
)
 
(1,608,647
)
Net property and equipment
 
2,119,075

 
3,354,082

Deferred income taxes
 
68,069

 
—

Derivatives
 
97,850

 
117,788

Investment in equity method investee
 
160,206

 
58,288

Other assets, net
 
11,853

 
15,290

Total assets
 
$
2,832,495

 
$
3,910,701

Liabilities and stockholders' equity
 
 
 
 

Current liabilities:
 
 
 
 

Accounts payable
 
$
23,647

 
$
39,008

Undistributed revenue and royalties
 
38,346

 
65,438

Accrued capital expenditures
 
49,283

 
148,241

Deferred income taxes
 
68,069

 
71,191

Derivatives
 
—

 
115

Other current liabilities
 
112,204

 
101,032

Total current liabilities
 
291,549

 
425,025

Long-term debt, net
 
1,415,566

 
1,779,447

Deferred income taxes
 
—

 
105,754

Asset retirement obligations
 
32,557

 
31,042

Other noncurrent liabilities
 
4,141

 
6,232

Total liabilities
 
1,743,813

 
2,347,500

Commitments and contingencies
 


 


Stockholders' equity:
 
 
 
 
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued as of September 30, 2015 and December 31, 2014
 
—

 
—

Common stock, $0.01 par value, 450,000,000 shares authorized, and 213,839,893 and 143,686,491 issued, as of September 30, 2015 and December 31, 2014, respectively
 
2,138

 
1,437

Additional paid-in capital
 
2,079,240

 
1,309,171

(Accumulated deficit) retained earnings
 
(992,696
)
 
252,593

Total stockholders' equity
 
1,088,682

 
1,563,201

Total liabilities and stockholders' equity
 
$
2,832,495

 
$
3,910,701


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,
 
 
2015
 
2014
 
2015
 
2014
Revenues:






 
 

 
 

Oil, NGL and natural gas sales

$
104,607


$
199,490


$
348,279


$
555,576

Midstream service revenues

1,873


751


4,908


1,019

Sales of purchased oil
 
43,860

 
—

 
130,178

 
—

Total revenues

150,340


200,241


483,365


556,595

Costs and expenses:

 
 
 
 
 
 
 
Lease operating expenses

25,112


25,165


86,698


67,129

Production and ad valorem taxes
 
7,895

 
12,550

 
26,481

 
38,160

Midstream service expenses
 
1,092

 
1,225

 
4,263

 
3,596

Minimum volume commitments

—


675


5,235


1,779

Costs of purchased oil
 
46,961

 
—

 
132,578

 
—

General and administrative

22,913


27,078

 
67,976

 
84,284

Restructuring expenses
 
—

 
—

 
6,042

 
—

Accretion of asset retirement obligations

599


442


1,771


1,279

Depletion, depreciation and amortization

66,777


63,942


210,831


166,605

Impairment expense

906,850


—


1,397,327


—

Total costs and expenses

1,078,199


131,077


1,939,202


362,832

Operating income (loss)

(927,859
)

69,164


(1,455,837
)

193,763

Non-operating income (expense):




 
 
 
 
 
Gain (loss) on derivatives, net

142,580


92,790


141,836


(1,447
)
Income (loss) from equity method investee

2,104


(61
)

4,585


(86
)
Interest expense

(23,348
)

(30,549
)

(79,732
)

(90,192
)
Interest and other income

92


33


388


310

Loss on early redemption of debt
 
—

 
—

 
(31,537
)
 
—

Write-off of debt issuance costs

—


—

 
—

 
(124
)
Loss on disposal of assets, net

(94
)

(2,192
)

(1,937
)

(2,418
)
Non-operating income (expense), net

121,334


60,021


33,603


(93,957
)
Income (loss) before income taxes

(806,525
)

129,185


(1,422,234
)

99,806

Income tax (expense) benefit:












Deferred

(41,258
)

(45,778
)

176,945


(35,511
)
Total income tax (expense) benefit

(41,258
)

(45,778
)

176,945


(35,511
)
Net income (loss)

$
(847,783
)
 
$
83,407


$
(1,245,289
)

$
64,295

Net income (loss) per common share:







 




Basic

$
(4.01
)

$
0.59


$
(6.38
)
 
$
0.46

Diluted

$
(4.01
)
 
$
0.58


$
(6.38
)
 
$
0.45

Weighted-average common shares outstanding:







 

 
 

Basic

211,204


141,413


195,081

 
141,261

Diluted

211,204


143,813


195,081

 
143,583

 
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, 2014
 
143,686

 
$
1,437

 
$
1,309,171

 
—

 
$
—

 
$
252,593

 
$
1,563,201

Restricted stock awards
 
1,894

 
18

 
(18
)
 
—

 
—

 
—

 
—

Restricted stock forfeitures
 
(519
)
 
(5
)
 
5

 
—

 
—

 
—

 
—

Vested restricted stock exchanged for tax withholding
 
—

 
—

 
—

 
221

 
(2,749
)
 
—

 
(2,749
)
Retirement of treasury stock
 
(221
)
 
(2
)
 
(2,747
)
 
(221
)
 
2,749

 
—

 
—

Equity issuance, net of offering costs
 
69,000

 
690

 
753,473

 
—

 
—

 
—

 
754,163

Stock-based compensation
 
—

 
—

 
19,356

 
—

 
—

 
—

 
19,356

Net loss
 
—

 
—

 
—

 
—

 
—

 
(1,245,289
)
 
(1,245,289
)
Balance, September 30, 2015
 
213,840

 
$
2,138

 
$
2,079,240

 
—

 
$
—

 
$
(992,696
)
 
$
1,088,682

 
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,
 
 
2015
 
2014
Cash flows from operating activities:

 


 

Net income (loss)

$
(1,245,289
)

$
64,295

Adjustments to reconcile net income (loss) to net cash provided by operating activities:






Deferred income tax (benefit) expense

(176,945
)

35,511

Depletion, depreciation and amortization

210,831


166,605

Impairment expense

1,397,327


—

Loss on early redemption of debt
 
31,537

 
—

Bad debt expense

107

 
—

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

17,933


16,919

Mark-to-market on derivatives:






(Gain) loss on derivatives, net

(141,836
)

1,447

Cash settlements received (paid) for matured derivatives, net

175,879


(1,320
)
Cash settlements received for early terminations of derivatives, net

—


76,660

Change in net present value of deferred premiums paid for derivatives

141


170

Cash premiums paid for derivatives

(3,918
)

(5,599
)
Amortization of debt issuance costs

3,612


3,823

Cash settlement of performance unit awards
 
(2,738
)
 
—

Other, net

(876
)

4,137

Decrease (increase) in accounts receivable
 
26,147

 
(26,449
)
Increase in other assets
 
(1,234
)
 
(8,656
)
(Decrease) increase in accounts payable
 
(15,361
)
 
39,456

(Decrease) increase in undistributed revenues and royalties
 
(27,092
)
 
14,105

Decrease in other accrued liabilities
 
(25,676
)
 
(7,908
)
Increase in other noncurrent liabilities
 
221

 
2,373

Increase in fair value of performance unit awards
 
2,734

 
767

Net cash provided by operating activities
 
225,504

 
376,336

Cash flows from investing activities:






Capital expenditures:






Acquisition of oil and natural gas properties

—

 
(6,493
)
Acquisition of mineral interests

—


(7,305
)
Oil and natural gas properties

(490,351
)

(925,121
)
Midstream service assets

(35,237
)

(45,263
)
Other fixed assets

(8,539
)

(13,612
)
Investment in equity method investee
 
(63,011
)
 
(37,581
)
Proceeds from dispositions of capital assets, net of costs

65,261


1,627

Net cash used in investing activities

(531,877
)

(1,033,748
)
Cash flows from financing activities:






Borrowings on Senior Secured Credit Facility

310,000


75,000

Payments on Senior Secured Credit Facility

(475,000
)

—

Issuance of March 2023 Notes
 
350,000


—

Issuance of January 2022 Notes

—


450,000

Redemption of January 2019 Notes
 
(576,200
)
 
—

Proceeds from issuance of common stock, net of offering costs
 
754,163

 
—

Purchase of treasury stock

(2,749
)

(4,075
)
Proceeds from exercise of employee stock options

—


1,885

Payments for debt issuance costs

(6,759
)

(7,791
)
Net cash provided by financing activities

353,455


515,019

Net increase (decrease) in cash and cash equivalents

47,082


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

29,321


198,153

Cash and cash equivalents, end of period

$
76,403


$
55,760

 
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)

Note 1—Organization
Laredo Petroleum, Inc. ("Laredo"), together with its subsidiaries, Laredo Midstream Services, LLC ("LMS") and Garden City Minerals, LLC ("GCM"), is an independent energy company focused on the acquisition, exploration and development of oil and natural gas properties primarily in the Permian Basin in West Texas. LMS and GCM (together, the "Guarantors") guarantee all of Laredo's debt instruments.
In these notes, the "Company," (i) when used in the present tense, prospectively or from October 24, 2014, refers to Laredo, LMS and GCM collectively, unless the context indicates otherwise or (ii) when used for historical periods from December 31, 2013 to October 23, 2014, refers to Laredo and LMS collectively, unless the context indicates otherwise. All amounts, dollars and percentages presented in these unaudited consolidated financial statements and the related notes are rounded and therefore approximate.
The Company operates in two business segments, which are (i) exploration and production and (ii) midstream and marketing. The exploration and production segment is engaged in the acquisition, exploration and development of oil and natural gas properties primarily in the Permian Basin in West Texas. The midstream and marketing segment provides Laredo's exploration and production segment and certain third parties with (i) any products and services that need to be delivered by midstream infrastructure, including oil and natural gas gathering services as well as rig fuel, natural gas lift and water in Laredo's primary drilling corridors and (ii) takeaway optionality in the field and firm service commitments to maximize Laredo's oil, NGL and natural gas revenues.
Note 2—Basis of presentation and significant accounting policies
a.    Basis of presentation
The accompanying unaudited consolidated financial statements were derived from the historical accounting records of the Company and reflect the historical financial position, results of operations and cash flows for the periods described herein. The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). All material intercompany transactions and account balances have been eliminated in the consolidation of accounts. The Company uses the equity method of accounting to record its net interests when the Company holds 20% to 50% of the voting rights and/or has the ability to exercise significant influence but does not control the entity. Under the equity method, the Company's proportionate share of the investee's net income (loss) is included in the unaudited consolidated statements of operations. See Note 14 for additional discussion of the Company's equity method investment.
The accompanying consolidated financial statements have not been audited by the Company's independent registered public accounting firm, except that the consolidated balance sheet as of December 31, 2014 is derived from audited consolidated financial statements. See Notes 2.g, 5.g and 18 for discussion regarding the Company's early-adoption of new accounting guidance regarding the presentation of debt issuance costs. 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, 2015, results of operations for the three and nine months ended September 30, 2015 and 2014 and cash flows for the nine months ended September 30, 2015 and 2014.
Certain disclosures have been condensed or omitted from these unaudited consolidated financial statements. Accordingly, these unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in the 2014 Annual Report.
b.    Use of estimates in the preparation of interim unaudited consolidated financial statements
The preparation of the accompanying unaudited consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ. The interim results reflected in the unaudited consolidated financial statements are not necessarily indicative of the results that may be expected for other interim periods or for the full year.
Significant estimates include, but are not limited to, (i) estimates of the Company's reserves of oil, NGL and natural gas, (ii) future cash flows from oil and natural gas properties, (iii) depletion, depreciation and amortization, (iv) 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, commodity deferred premiums and performance unit awards.

5
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)

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.
c.    Reclassifications
Certain amounts in the accompanying unaudited consolidated financial statements have been reclassified to conform to the 2015 presentation. These reclassifications had no impact to previously reported net income or loss, stockholders' equity or cash flows.
d.    Accounts receivable
The Company sells oil, NGL and natural gas to various customers and participates with other parties in the development and operation of oil and natural gas properties. The Company's accounts receivable 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 amounts 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, 2015
 
December 31, 2014
Oil, NGL and natural gas sales
 
$
34,512

 
$
57,070

Joint operations, net(1)
 
25,553

 
33,808

Matured derivatives
 
21,729

 
16,098

Purchased oil and other product sales
 
14,436

 
18,917

Other
 
4,445

 
1,036

Total
 
$
100,675

 
$
126,929

______________________________________________________________________________
(1)
Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.2 million and $0.8 million as of September 30, 2015 and December 31, 2014, respectively.
e.    Derivatives
The Company uses derivatives to reduce 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 in the form of collars, swaps, puts and basis swaps.
Derivatives are recorded at fair value and are presented net on the unaudited consolidated balance sheets as assets or liabilities. The Company nets the fair value of derivatives by counterparty where the right of offset exists. The Company determines the fair value of its derivatives by utilizing pricing models for substantially similar instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties (see Notes 8 and 9). 

6
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)

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 8).
f.    Property and equipment
The following table sets forth the Company's property and equipment for the periods presented:
(in thousands)
 
September 30, 2015
 
December 31, 2014
Evaluated oil and natural gas properties
 
$
4,895,042

 
$
4,446,781

Less accumulated depletion and impairment
 
(3,180,822
)
 
(1,586,237
)
Evaluated oil and natural gas properties, net
 
1,714,220

 
2,860,544

 
 
 
 
 
Unevaluated properties not being amortized
 
225,045

 
342,731

 
 
 
 
 
Midstream service assets
 
149,068

 
117,052

Less accumulated depreciation
 
(14,057
)
 
(8,590
)
Midstream service assets, net
 
135,011

 
108,462

 
 
 
 
 
Depreciable other fixed assets
 
47,220

 
42,933

Less accumulated depreciation and amortization
 
(17,315
)
 
(13,820
)
Depreciable other fixed assets, net
 
29,905

 
29,113

 
 
 
 
 
Land
 
14,894

 
13,232

 
 
 
 
 
Total property and equipment, net
 
$
2,119,075

 
$
3,354,082

For the three months ended September 30, 2015 and 2014, depletion expense was $15.32 per barrel of oil equivalent ("BOE") sold and $20.25 per BOE sold, respectively. For the nine months ended September 30, 2015 and 2014, depletion expense was $15.87 per BOE sold and $19.83 per BOE sold, respectively.
The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain related employee costs, incurred for the purpose of finding oil and natural gas are capitalized and amortized on a composite unit of production method based on proved oil, NGL and natural gas reserves. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Costs, including related employee costs, associated with production and general corporate activities are expensed in the period incurred. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, NGL and natural gas.
The Company excludes the costs directly associated with acquisition and evaluation of unevaluated properties from the depletion calculation until it is determined whether or not proved reserves can be assigned to the properties. The Company capitalizes a portion of its interest costs on its unevaluated properties. Capitalized interest becomes a part of the cost of the unevaluated properties and is subject to depletion when proved reserves can be assigned to the associated properties. All items classified as unevaluated property are assessed on a quarterly basis for possible impairment or reduction in value. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of evaluated reserves and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion.
The full cost ceiling is based principally on the estimated future net cash flows from proved oil and natural gas properties discounted at 10%. Full cost companies are required to use the unweighted arithmetic average first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period ("SEC Prices"), unless prices were defined by contractual arrangements, to calculate the discounted future revenues. In the event the unamortized cost of evaluated

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

oil and natural gas properties being amortized exceeds the full cost ceiling, as defined by the SEC, the excess is charged to expense in the period such excess occurs. Once incurred, a write-down of oil and natural gas properties is not reversible.
The full cost ceiling value of the Company's reserves was calculated based on SEC Prices as of September 30, 2015, which do not include derivative transactions, of (i) $55.73 per barrel for oil, (ii) $21.87 per barrel for NGL and (iii) $2.89 per MMBtu for natural gas, adjusted by area for energy content, transportation fees and regional price differentials. Using these SEC Prices, the Company's net book value of evaluated oil and natural gas properties exceeded the full cost ceiling amount as of September 30, 2015. As a result, the Company recorded a third-quarter non-cash full cost ceiling impairment of $906.4 million.
As of June 30, 2015, the full cost ceiling value of the Company's reserves was calculated based on SEC Prices as of June 30, 2015, which did not include derivative transactions, of (i) $68.17 per barrel for oil, (ii) $26.73 per barrel for NGL and (iii) $3.22 per MMBtu for natural gas, adjusted by area for energy content, transportation fees, and regional price differentials. Using these SEC Prices, the Company's net book value of evaluated oil and natural gas properties exceeded the full cost ceiling amount as of June 30, 2015. As a result, the Company recorded a second-quarter non-cash full cost ceiling impairment of $488.0 million.
Full cost ceiling impairment expense for the three and nine months ended September 30, 2015 in the unaudited consolidated statements of operations was $906.4 million and $1.39 billion, respectively. The Company's net book value of evaluated oil and natural gas properties did not exceed the full cost ceiling amount at March 31, 2014, June 30, 2014 or September 30, 2014. The amounts are included in "Impairment expense" in the unaudited consolidated statements of operations and in "Other operating costs and expenses" for the Company's exploration and production segment presented in Note 16.
g.    Debt issuance costs
Debt issuance fees, which are recorded at cost, net of amortization, are amortized over the life of the respective debt agreements utilizing the effective interest and straight-line methods. The Company capitalized $6.8 million of debt issuance costs during the nine months ended September 30, 2015 mainly as a result of the issuance of the March 2023 Notes (as defined below). The Company capitalized $7.8 million of debt issuance 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 had total debt issuance costs of $25.0 million and $28.5 million, net of accumulated amortization of $15.9 million and $19.4 million, as of September 30, 2015 and December 31, 2014, respectively.
The Company wrote-off approximately $6.6 million of debt issuance costs during the nine months ended September 30, 2015 as a result of the early redemption of the January 2019 Notes (as defined below), which are included in the unaudited consolidated statements of operations in the "Loss on early redemption of debt" line item. During the nine months ended September 30, 2014, the Company wrote-off approximately $0.1 million of debt issuance costs as a result of changes in the borrowing base of the Senior Secured Credit Facility (as defined below) due to the issuance of the January 2022 Notes, which are included in the unaudited consolidated statements of operations in the "Write-off of debt issuance costs" line item. See Notes 5.a, 5.b, 5.d and 5.e for definition of and information regarding the March 2023 Notes, January 2022 Notes, January 2019 Notes and the Senior Secured Credit Facility, respectively.
As of September 30, 2015, the Company has early-adopted new guidance that seeks to simplify the presentation of debt issuance costs and has applied its provisions retrospectively. The adoption of this standard resulted in the reclassification of $19.4 million and $21.8 million of unamortized debt issuance costs related to the Company's senior unsecured notes from "Other assets, net" to "Long-term debt, net" within its consolidated balance sheets as of September 30, 2015 and December 31, 2014, respectively. Other than this reclassification, the adoption of this standard did not have an impact on the Company's unaudited consolidated financial statements. Debt issuance costs related to the Senior Secured Credit Facility remain recorded in "Other assets, net" on the Company's unaudited consolidated balance sheets. See Notes 5.g and 18 for additional discussion of debt issuance costs.

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

Future amortization expense of debt issuance costs as of September 30, 2015 is as follows:
(in thousands)
 
 
Remaining 2015

$
1,116

2016

4,503

2017

4,575

2018

4,349

2019

2,915

Thereafter

7,589

Total

$
25,047

h.    Other current liabilities
Other current liabilities consist of the following components for the periods presented:
(in thousands)
 
September 30, 2015
 
December 31, 2014
Capital contribution payable to equity method investee(1)
 
$
34,322

 
$
—

Accrued interest payable
 
21,635

 
37,689

Costs of purchased oil payable
 
15,047

 
20,114

Lease operating expense payable
 
14,117

 
11,963

Other accrued liabilities
 
27,083

 
31,266

Total other current liabilities
 
$
112,204

 
$
101,032

______________________________________________________________________________
(1)
See Notes 14, 15 and 19.a for additional discussion regarding our equity method investee.
i.    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 removal and/or remediation costs for midstream assets, (iv) estimated remaining life of 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.
The following reconciles the Company's asset retirement obligation liability for the periods presented:
(in thousands)
 
Nine months ended September 30, 2015
 
Year ended December 31, 2014
Liability at beginning of period
 
$
32,198

 
$
21,743

Liabilities added due to acquisitions, drilling, midstream service asset construction and other
 
1,675

 
6,370

Accretion expense
 
1,771

 
1,787

Liabilities settled upon plugging and abandonment
 
(122
)
 
(450
)
Liabilities removed due to sale of property
 
(2,005
)
 
—

Revision of estimates
 
—

 
2,748

Liability at end of period
 
$
33,517

 
$
32,198

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


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

k.    Fair value measurements
The carrying amounts reported in the unaudited consolidated balance sheets for cash and cash equivalents, accounts receivable, accounts payable, undistributed revenue and royalties, accrued capital expenditures and other accrued assets and liabilities approximate their fair values. See Note 5.f for fair value disclosures related to the Company's debt obligations. The Company carries its derivatives at fair value. See Notes 8 and 9 for details regarding the fair value of the Company's derivatives.
l.    Compensation awards
Stock-based compensation expense, net of amounts capitalized, is included in "General and administrative" in the unaudited consolidated statements of operations over the awards' vesting periods and is based on the awards' grant date fair value. The Company utilizes the closing stock price on the grant date, less an expected forfeiture rate, to determine the fair 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. The Company capitalizes a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration and development of its oil and 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 6 for further discussion regarding the restricted stock awards, restricted stock option awards, performance share awards and performance unit awards.
m. Long-lived assets, materials and supplies and line-fill
Impairment losses are recorded on property and equipment used in operations and other long-lived assets when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets' carrying amount. Impairment is measured based on the excess of the carrying amount over the fair value of the asset.
Materials and supplies are used in developing oil and natural gas properties, are carried at the lower of cost or market ("LCM") and are included in "Other current assets" and "Other assets, net" on the unaudited consolidated balance sheets. The market price for materials and supplies is determined utilizing the Company's recent prices paid to acquire materials. During the nine months ended September 30, 2015, the Company reduced materials and supplies by $2.3 million in order to reflect the balance at LCM. The adjustment is included in "Impairment expense" in the unaudited consolidated statements of operations and in "Other operating costs and expenses" for the Company's exploration and production segment presented in Note 16. The Company determined an LCM adjustment was not necessary for materials and supplies during the three months ended September 30, 2015, or during the three and nine months ended September 30, 2014.
The minimum volume of product in a pipeline system that enables the system to operate is known as line-fill, and is generally not available to be withdrawn from the pipeline system until the expiration of the transportation contract. Beginning in the fourth quarter of 2014, the Company owns oil line-fill in third-party pipelines, which is accounted for at LCM with cost determined using the weighted-average cost method, and is included in "Other assets, net" on the unaudited consolidated balance sheets. The LCM adjustment is determined utilizing a quoted market price adjusted for regional price differentials (Level 2). For the three and nine months ended September 30, 2015, the Company recorded LCM adjustments of $0.4 million

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

and $0.5 million, respectively, related to its line-fill, which is included in "Impairment expense" in the unaudited consolidated statements of operations and as "Other operating costs and expenses" for the Company's midstream and marketing segment presented in Note 16.
n.    Environmental
The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, among other things, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed in the period incurred. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. Management believes no materially significant liabilities of this nature existed as of September 30, 2015 or December 31, 2014.
o.    Non-cash investing and supplemental cash flow information
The following presents the non-cash investing and supplemental cash flow information for the periods presented:
 
 
Nine months ended September 30,
(in thousands)
 
2015
 
2014
Non-cash investing information:
 
 
 
 
Change in accrued capital expenditures
 
$
(98,958
)
 
$
23,945

Change in accrued capital contribution to equity method investee(1)
 
$
34,322

 
$
(2,598
)
Capitalized asset retirement cost
 
$
1,675

 
$
4,767

Supplemental cash flow information:
 
 
 
 
Capitalized interest
 
$
227

 
$
51

______________________________________________________________________________
(1)
See Notes 14, 15 and 19.a for additional discussion regarding our equity method investee.
Note 3—Equity offering
On March 5, 2015, the Company completed the sale of 69,000,000 shares of Laredo's common stock at a price to the public of $11.05 per share (the "March 2015 Equity Offering"). The Company received net proceeds of $754.2 million, after underwriting discounts, commissions and offering expenses. Entities affiliated with Warburg Pincus LLC ("Warburg Pincus") purchased 29,800,000 shares in the March 2015 Equity Offering, following which Warburg Pincus owned 41.0% of Laredo's common stock. There were no comparative offerings of the Company's stock during the three or nine months ended September 30, 2014.
Note 4—Acquisitions
a. Divestiture of non-strategic assets
On September 15, 2015, the Company completed the sale of non-strategic and primarily non-operated properties and associated production totaling 6,060 net acres and 123 producing properties in the Midland Basin to a third-party buyer for a sales price of $65.5 million. After transaction costs and adjustments at closing reflecting an economic effective date of July 1, 2015, the net proceeds were $65.2 million, net of working capital adjustments and subject to post-closing cost adjustments. The purchase price, excluding post-closing adjustments, was allocated to oil and natural gas properties pursuant to the rules governing full cost accounting.
Effective at closing, the operations and cash flows of these properties were eliminated from the ongoing operations of the Company and the Company has no continuing involvement in the properties. This divestiture does not represent a strategic shift and will not have a major effect on the Company's operations or financial results.
    

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

The following table presents revenues and expenses of the oil and natural gas properties sold included in the accompanying unaudited consolidated statements of operations for the periods presented:
 
 
Three months ended September 30,
 
Nine months ended September 30,
(in thousands)
 
2015
 
2014
 
2015
 
2014
Oil, NGL and natural gas sales
 
$
1,371

 
$
5,644

 
$
5,419

 
$
15,574

Expenses(1)
 
1,781

 
3,042

 
6,565

 
7,789

_____________________________________________________________________________
(1)
Expenses include (i) lease operating expense, (ii) production and ad valorem tax expense, (iii) accretion expense and (iv) depletion.
b.    2014 acquisition of leasehold interests
On August 28, 2014, the Company completed a material acquisition of leasehold interests totaling 8,156 net acres in the Midland Basin, primarily within the Company's core development area, for $192.5 million. The acquisition was accounted for as an acquisition of assets.
c.    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 Midland Basin for $7.3 million. These mineral interests entitle the Company to receive royalty payments on all production from this acreage with no additional future capital or operating expenses required. As such, the purchase was accounted for as an acquisition of assets.
d.    2014 acquisitions of evaluated and unevaluated oil and natural gas properties
The Company accounts for acquisitions of evaluated and unevaluated oil and natural gas properties under the acquisition method of accounting. Accordingly, the Company conducts assessments of net assets acquired and recognizes amounts for identifiable assets acquired and liabilities assumed at the estimated acquisition date fair values, while transaction 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 evaluated and unevaluated 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 unevaluated 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 evaluated and unevaluated 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 evaluated and unevaluated 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.
Note 5—Debt
a.   March 2023 Notes
On March 18, 2015, the Company completed an offering of $350.0 million in aggregate principal amount of 6 1/4% senior unsecured notes due 2023 (the "March 2023 Notes"), and entered into an Indenture (the "Base Indenture"), as supplemented by the Supplemental Indenture (the "Supplemental Indenture" and, together with the Base Indenture, the "Indenture"), among Laredo, LMS and GCM, as guarantors, and Wells Fargo Bank, National Association, as trustee. The March 2023 Notes will mature on March 15, 2023 with interest accruing at a rate of 6 1/4% per annum and payable semi-annually in cash in arrears on March 15 and September 15 of each year, commencing September 15, 2015. The March 2023 Notes are fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain automatic customary releases, including the sale, disposition, or transfer of all of the capital stock or of all or substantially all of the assets of a subsidiary guarantor to one or more persons that are not the Company or a restricted subsidiary, exercise of legal defeasance or covenant defeasance options or satisfaction and discharge of

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

the Indenture, designation of a subsidiary guarantor as a non-guarantor restricted subsidiary or as an unrestricted subsidiary in accordance with the Indenture, release from guarantee under the Senior Secured Credit Facility (as defined below), or liquidation or dissolution (collectively, the "Releases").
The March 2023 Notes were offered and sold pursuant to a prospectus supplement dated March 4, 2015 and the base prospectus dated March 22, 2013, relating to the Company's effective shelf registration statement on Form S-3 (File No. 333-187479). The Company received net proceeds of $343.6 million from the offering, after deducting the underwriters' discount and the estimated outstanding offering expenses. In April 2015, the Company used the proceeds of the offering to fund a portion of the Company's redemption of the January 2019 Notes (as defined below). See Note 5.d for additional discussion of this early redemption.
The Company may redeem, at its option, all or part of the March 2023 Notes at any time on or after March 15, 2018, at the applicable redemption price plus accrued and unpaid interest to, but not including, the date of redemption. Further, before March 15, 2018, the Company may on one or more occasions redeem up to 35% of the aggregate principal amount of the March 2023 Notes in an amount not exceeding the net proceeds from one or more private or public equity offerings at a redemption price of 106.25% of the principal amount of the March 2023 Notes, plus accrued and unpaid interest to the date of redemption, if at least 65% of the aggregate principal amount of the March 2023 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 March 15, 2016, the Company may redeem all, but not less than all, of the March 2023 Notes at a redemption price equal to 110% of the principal amount of the March 2023 Notes plus any accrued and unpaid interest to, but not including, the date of redemption.
b.    January 2022 Notes
On January 23, 2014, the Company completed an offering of $450.0 million in aggregate principal amount of 5 5/8% senior unsecured notes due 2022 (the "January 2022 Notes"). The January 2022 Notes will mature on January 15, 2022 and bear an interest rate of 5 5/8% per annum, payable semi-annually, in cash in arrears on January 15 and July 15 of each year, commencing July 15, 2014. The January 2022 Notes are fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain Releases.
c.    May 2022 Notes
On April 27, 2012, the Company completed an offering of $500.0 million in aggregate principal amount of 7 3/8% senior unsecured notes due 2022 (the "May 2022 Notes"). The May 2022 Notes will mature on May 1, 2022 and bear an interest rate of 7 3/8% per annum, payable semi-annually, in cash in arrears on May 1 and November 1 of each year, commencing November 1, 2012. The May 2022 Notes are fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain Releases.
d.    January 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 "January 2019 Notes"). The January 2019 Notes were due to mature on February 15, 2019 and bore 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 January 2019 Notes were fully and unconditionally guaranteed on a senior unsecured basis by LMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain Releases.
On April 6, 2015 (the "Redemption Date"), the entire $550.0 million outstanding principal amount of the January 2019 Notes was redeemed at a redemption price of 104.750% of the principal amount of the January 2019 Notes, plus accrued and unpaid interest up to the Redemption Date. The Company recognized a loss on extinguishment of $31.5 million related to the difference between the redemption price and the net carrying amount of the extinguished January 2019 Notes.
e.    Senior Secured Credit Facility
As of September 30, 2015, the Fourth Amended and Restated Credit Agreement (as amended, the "Senior Secured Credit Facility"), which matures on November 4, 2018, had a maximum credit amount of $2.0 billion, a borrowing base of $1.25 billion and an aggregate elected commitment of $1.0 billion with $135.0 million outstanding and was subject to an interest rate of 1.7500%. It contains both financial and non-financial covenants, all of which the Company was in compliance with as of September 30, 2015. 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

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

the Senior Secured Credit Facility. Additionally, the Senior Secured Credit Facility provides for the issuance of letters of credit, limited to the lesser of total capacity or $20.0 million. No letters of credit were outstanding as of September 30, 2015 or 2014.
See Note 19.b for information regarding changes, subsequent to September 30, 2015, in the Senior Secured Credit Facility's borrowing base.
f.    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 for the periods presented:
 
 
September 30, 2015
 
December 31, 2014
(in thousands)
 
Carrying
value
 
Fair
value
 
Carrying
value
 
Fair
value
January 2019 Notes(1)
 
$
—

 
$
—

 
$
551,295

 
$
550,000

January 2022 Notes
 
450,000

 
405,000

 
450,000

 
396,014

May 2022 Notes
 
500,000

 
487,500

 
500,000

 
467,529

March 2023 Notes
 
350,000

 
318,500

 
—

 
—

Senior Secured Credit Facility
 
135,000

 
134,981

 
300,000

 
300,279

Total value of debt
 
$
1,435,000

 
$
1,345,981

 
$
1,801,295

 
$
1,713,822

______________________________________________________________________________
(1)
The carrying value of the January 2019 Notes includes the October Notes unamortized bond premium of $1.3 million as of December 31, 2014.
The fair values of the debt outstanding on the January 2019 Notes, January 2022 Notes, May 2022 Notes and the March 2023 Notes were determined using the September 30, 2015 and December 31, 2014 quoted market price (Level 1) for each respective instrument. The fair values of the outstanding debt on the Senior Secured Credit Facility as of September 30, 2015 and December 31, 2014 were estimated utilizing pricing models for similar instruments (Level 2). See Note 9 for information about fair value hierarchy levels.
g.    Debt issuance costs
The following tables summarize the net presentation of the Company's long-term debt and debt issuance cost on the unaudited consolidated balance sheets for the periods presented:
 
 
September 30, 2015
 
December 31, 2014
(in thousands)
 
Carrying
value
 
Debt issuance costs, net
 
Long-term debt, net
 
Carrying
value
 
Debt issuance costs, net
 
Long-term debt, net
January 2019 Notes
 
$
—

 
$
—

 
$
—

 
$
551,295

 
$
(7,031
)
 
$
544,264

January 2022 Notes
 
450,000

 
(6,183
)
 
443,817

 
450,000

 
(6,916
)
 
443,084

May 2022 Notes
 
500,000

 
(7,281
)
 
492,719

 
500,000

 
(7,901
)
 
492,099

March 2023 Notes
 
350,000

 
(5,970
)
 
344,030

 
—

 
—

 
—

Senior Secured Credit Facility(1)
 
135,000

 
—

 
135,000

 
300,000

 
—

 
300,000

Total
 
$
1,435,000

 
$
(19,434
)
 
$
1,415,566

 
$
1,801,295

 
$
(21,848
)
 
$
1,779,447

______________________________________________________________________________
(1)
Debt issuance costs related to our Senior Secured Credit Facility are recorded in "Other assets, net" on the unaudited consolidated balance sheets.
Note 6—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 option 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 awards expected to vest over the requisite service period as a charge against earnings, net of amounts capitalized. The Company's stock-based compensation awards are

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

accounted for as equity instruments and its performance unit awards are accounted for as liability awards. Stock-based compensation is included in "General and administrative" in the unaudited consolidated statements of operations. The Company capitalizes a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration and development of oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included as an addition to "Oil and natural gas properties" in the unaudited consolidated balance sheets.
a.    Restricted stock awards
All restricted stock awards are treated as issued and outstanding in the accompanying unaudited consolidated financial statements. Per the award agreement terms, if an employee terminates employment prior to the restriction lapse date, for reasons other than death or disability, the awarded shares are forfeited and canceled and are no longer considered issued and outstanding. If the employee's termination of employment is by reason of death or disability, all of the holder's restricted stock will automatically vest. 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 of the grant date and (v) fully on the third anniversary of the grant date. Restricted stock awards granted to non-employee directors vest fully on the first anniversary of the grant date.
The following table reflects the outstanding restricted stock awards for the nine months ended September 30, 2015:
(in thousands, except for weighted-average grant date fair values)
 
Restricted
stock
awards
 
Weighted-average
grant date
fair value (per award)
Outstanding as of December 31, 2014
 
2,205

 
$
22.63

Granted
 
1,894

 
$
11.98

Forfeited
 
(519
)
 
$
20.90

Vested(1)
 
(984
)
 
$
22.39

Outstanding as of September 30, 2015
 
2,596

 
$
15.32

______________________________________________________________________________
(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 7 for additional discussion regarding the tax impact of vested restricted stock awards.
The Company utilizes the closing stock price on the grant date to determine the fair value of service vesting restricted stock awards. As of September 30, 2015, unrecognized stock-based compensation related to the restricted stock awards expected to vest was $26.4 million. Such cost is expected to be recognized over a weighted-average period of 1.90 years.
b.    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 grant date. The following table reflects the stock option award activity for the nine months ended September 30, 2015:
(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 as of December 31, 2014
 
1,367

 
$
20.76

 
8.17
Granted
 
632

 
$
11.93

 

Exercised
 
—

 
$
—

 

Expired or canceled
 
(58
)
 
$
19.51

 

Forfeited
 
(139
)
 
$
18.17

 

Outstanding as of September 30, 2015
 
1,802

 
$
17.90

 
8.05
Vested and exercisable at end of period(1)
 
569

 
$
20.78

 
6.89
Expected to vest at end of period(2)
 
1,214

 
$
16.49

 
8.60
_____________________________________________________________________________
(1)
The vested and exercisable options as of September 30, 2015 had no aggregate intrinsic value.
(2)
The options expected to vest as of September 30, 2015 had no aggregate intrinsic value.

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

The Company utilizes the Black-Scholes option pricing model to determine the fair value 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, 2015, unrecognized stock-based compensation related to the restricted stock option awards expected to vest was $8.0 million. Such cost is expected to be recognized over a weighted-average period of 2.51 years.
The assumptions used to estimate the fair value of restricted stock options granted on February 27, 2015 are as follows:
Risk-free interest rate(1)
1.70
%
Expected option life(2)
6.25 years

Expected volatility(3)
52.59
%
Fair value per stock option
$
6.15

______________________________________________________________________________
(1)
U.S. Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, correlating the treasury yield terms to the expected life of the 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 its 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.
c.    Performance share awards
The performance share awards granted to management on February 27, 2015 (the "2015 Performance Share Awards") and on February 27, 2014 (the "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 to determine the grant date fair value of these awards. The Company has determined these awards are equity awards and recognizes the associated expense on a straight-line basis over the three-year requisite service period of the awards. These awards will be settled, if at all, in stock at the end of the requisite service period based on the achievement of certain performance criteria.
The 2015 Performance Share Awards have a performance period of January 1, 2015 to December 31, 2017 and any shares earned under such awards are expected to be issued in the first quarter of 2018 if the performance criteria are met. During the nine months ended September 30, 2015, 602,501 2015 Performance Share Awards were granted and all remain outstanding as of September 30, 2015. The 271,667 outstanding 2014 Performance Share Awards have a performance period of

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

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 are met.
As of September 30, 2015, unrecognized stock-based compensation related to the 2015 Performance Share Awards and the 2014 Performance Share Awards was $11.4 million. Such cost is expected to be recognized over a weighted-average period of 2.09 years.
The assumptions used to estimate the fair value of the 2015 Performance Share Awards granted on February 27, 2015 are as follows:
Risk-free rate(1)
 
0.95
%
Dividend yield
 
—
%
Expected volatility(2)
 
53.78
%
Laredo stock closing price as of February 27, 2015
 
$
11.93

Fair value per performance share
 
$
16.23

______________________________________________________________________________
(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.
d.    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)
 
2015

2014

2015

2014
Restricted stock award compensation, net of amounts capitalized
 
$
4,588

 
$
4,866

 
$
11,724

 
$
13,303

Restricted stock option award compensation, net of amounts capitalized
 
925

 
763

 
2,740


2,226

Restricted performance share award compensation, net of amounts capitalized
 
1,364

 
565

 
3,469


1,390

Total stock-based compensation, net of amounts capitalized
 
$
6,877

 
$
6,194

 
$
17,933


$
16,919

e.    Performance unit awards
The performance unit awards issued to management on February 15, 2013 (the "2013 Performance Unit Awards") and on February 3, 2012 (the "2012 Performance Unit Awards") are subject to a combination of market and service vesting criteria. These awards are accounted for as liability awards as they are settled in cash at the end of the requisite service period based on the achievement of certain performance criteria. A Monte Carlo simulation prepared by an independent third party is utilized to determine the fair values of these awards at the grant date and to re-measure the fair values 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 defined in each respective award agreement. 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 settled 2012 Performance Unit Awards had a performance period of January 1, 2012 to December 31, 2014 and, as their performance criteria were satisfied, they were paid at $100 per unit during the first quarter of 2015.
Compensation expense for the 2013 Performance Unit Awards is included in "General and administrative" in the Company's unaudited consolidated statements of operations, and the corresponding liability is included in "Other current

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

liabilities" on the unaudited consolidated balance sheets. Due to the quarterly re-measurement of the fair value of the 2013 Performance Unit Awards as of September 30, 2015, compensation expense for the three and nine months ended September 30, 2015 was $1.0 million and $2.7 million, respectively. Compensation expense related to the 2012 Performance Unit Awards and the 2013 Performance Unit Awards amounted to a $0.4 million reversal and $0.8 million for the three and nine months ended September 30, 2014, respectively.
Note 7—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 that 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 unaudited 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 unaudited 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 percent likely of being realized upon settlement. The Company had no unrecognized tax benefits related to uncertain tax positions in the unaudited consolidated financial statements as of September 30, 2015 or December 31, 2014.
The Company is subject to corporate income taxes and the Texas franchise tax. Income tax (expense) benefit for the periods presented consisted of the following:
 
 
Three months ended September 30,
 
Nine months ended September 30,
(in thousands)

2015
 
2014
 
2015
 
2014
Current taxes

$
—

 
$
—


$
—

 
$
—

Deferred taxes

(41,258
)
 
(45,778
)
 
176,945

 
(35,511
)
Income tax (expense) benefit

$
(41,258
)
 
$
(45,778
)

$
176,945

 
$
(35,511
)
Income tax (expense) benefit differed from amounts computed by applying the applicable federal income tax rate of 35% to pre-tax earnings as a result of the following:
 

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

2015
 
2014
 
2015
 
2014
Income tax benefit (expense) computed by applying the statutory rate

$
282,284

 
$
(45,215
)
 
$
497,782

 
$
(34,932
)
State income tax, net of federal tax benefit and increase in valuation allowance

(5,677
)
 
247

 
190

 
1,881

Non-deductible stock-based compensation

(45
)
 
(152
)
 
(151
)
 
(391
)
Stock-based compensation tax deficiency

(330
)
 
(4
)
 
(3,168
)
 
(160
)
Increase in deferred tax valuation allowance

(317,391
)
 
(22
)
 
(317,407
)
 
(1,134
)
Other items

(99
)
 
(632
)
 
(301
)
 
(775
)
Income tax (expense) benefit

$
(41,258
)
 
$
(45,778
)
 
$
176,945

 
$
(35,511
)
 
The effective tax rate on income (loss) before income taxes was 35% for the three months ended 2014 and 36% for the nine months ended September 30, 2014. The Company's effective tax rate is affected by recurring permanent differences, changes in valuation allowances and discrete items that may occur in any given year but are not consistent from year to year. For each of the three and nine months ended September 30, 2015, the Company recorded a valuation allowance of $326.2 million for its deferred tax assets due to uncertainty regarding their realization. As such, the effective tax rates on the Company's loss before income taxes for the same periods are not meaningful. No comparable amounts were recorded in the three and nine months ended September 30, 2014.

18
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 on the grant date 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, 2015 and 2014, 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 on the grant date. 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, for which the related income tax deduction was less than the expense previously recognized for book purposes. There were no stock options exercised during the three and nine months ended September 30, 2015. 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.
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)
 
2015
 
2014
 
2015
 
2014
Vesting of restricted stock
 
$
(336
)
 
$
(4
)
 
$
(3,225
)
 
$
(5
)
Exercise of restricted stock options
 
—

 
(1
)
 
—

 
(158
)
Tax expense due to shortfalls
 
$
(336
)
 
$
(5
)
 
$
(3,225
)
 
$
(163
)
Significant components of the Company's net deferred tax asset (liability) for the periods presented are as follows:
(in thousands)
 
September 30, 2015
 
December 31, 2014
Oil and natural gas properties, midstream service assets and other fixed assets
 
$
(27,816
)
 
$
(424,712
)
Net operating loss carry-forward
 
462,324

 
353,724

Derivatives
 
(107,862
)
 
(121,365
)
Stock-based compensation
 
11,051

 
10,718

Equity method investee
 
(19,079
)
 
—

Accrued bonus
 
3,448

 
3,256

Capitalized interest
 
2,851

 
3,049

Other
 
2,628

 
(316
)
Net deferred tax asset (liability) before valuation allowance
 
327,545

 
(175,646
)
Valuation allowance
 
(327,545
)
 
(1,299
)
Net deferred tax asset (liability)
 
$
—

 
$
(176,945
)
Deferred tax assets and liabilities were classified in the unaudited consolidated balance sheets as follows for the periods presented:
(in thousands)
 
September 30, 2015
 
December 31, 2014
Deferred tax asset
 
$
68,069

 
$
—

Deferred tax liability
 
(68,069
)
 
(176,945
)
Deferred tax asset (liability)
 
$
—

 
$
(176,945
)
The Company had federal net operating loss carry-forwards totaling $1.3 billion and state of Oklahoma net operating loss carry-forwards totaling $58.9 million as of September 30, 2015. These carry-forwards begin expiring in 2026. As of September 30, 2015, the Company believes a portion of the net operating loss carry-forwards are not fully realizable. The Company considered all available evidence, both positive and negative, in determining whether, based on the weight of that evidence, a valuation allowance was needed. Such consideration included estimated future projected earnings based on existing reserves and projected future cash flows from its oil and natural gas reserves (including the timing of those cash flows), the reversal of deferred tax liabilities recorded as of September 30, 2015, 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.


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

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, 2015, 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, 2015, a valuation allowance of $327.5 million has been recorded against the deferred tax asset.
The Company's income tax returns for the years 2012 through 2014 remain open and subject to examination by federal tax authorities and/or the tax authorities in Oklahoma and Texas, which are the jurisdictions where the Company has 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.
Note 8—Derivatives
a. 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 production. As of September 30, 2015, the Company had 37 open derivative contracts with financial institutions that extend from October 2015 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 "Gain (loss) on derivatives, net" line item.
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, which can be deferred until settlement, to enter into the put transaction. When the settlement price is below the floor price, the counterparty pays the Company an amount equal to the difference between the settlement price and the 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 transactions have an established fixed basis differential. The Company's oil basis swaps' differential is between the West Texas Intermediate-Argus Americas Crude (Midland) ("WTI Midland") index crude oil price and the WTI NYMEX (defined below) index crude oil price. When the WTI NYMEX price less the fixed basis differential is greater than the actual WTI Midland price, the difference multiplied by the hedged contract volume is paid to the Company by the counterparty. When the WTI NYMEX price less the fixed basis differential is less than the actual WTI 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 that hedged the differential between the Light Louisiana Sweet Argus and the Brent International Petroleum Exchange index oil prices. Prior to its unwind, the physical commodity contract qualified to be scoped out of mark-to-market accounting in accordance with the normal purchase and normal sale scope exemption. Once modified to settle financially in the unwind agreement, the contract ceased to qualify for the normal purchase and normal sale scope exemption, therefore requiring it to be marked-to-market. The Company received net proceeds of $76.7 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.
    

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

The following represents cash settlements received (paid) for derivatives for the periods presented:
 
 
Three months ended September 30,
 
Nine months ended September 30,
(in thousands)
 
2015
 
2014
 
2015
 
2014
Cash settlements received (paid) for matured commodity derivatives
 
$
66,142

 
$
4,531

 
$
175,879

 
$
(1,320
)
Early terminations of commodity derivatives received
 
—

 
—

 
—

 
76,660

Cash settlements received for derivatives, net
 
$
66,142

 
$
4,531

 
$
175,879

 
$
75,340


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

 
 
 
 

Puts:
 
 

 
 

 
 

Hedged volume (Bbl)
 
114,000

 
—

 
—

Weighted-average price ($/Bbl)
 
$
75.00

 
$
—

 
$
—

Swaps:
 
 

 
 

 
 

Hedged volume (Bbl)
 
168,000

 
1,573,800

 
—

Weighted-average price ($/Bbl)
 
$
96.56

 
$
84.82

 
$
—

Collars:
 
 

 
 

 
 

Hedged volume (Bbl)
 
1,641,880

 
3,654,000

 
2,628,000

Weighted-average floor price ($/Bbl)
 
$
79.81

 
$
73.99

 
$
77.22

Weighted-average ceiling price ($/Bbl)
 
$
95.41

 
$
89.63

 
$
97.22

Totals:
 
 
 
 
 
 
Total volume hedged with ceiling price (Bbl)
 
1,809,880

 
5,227,800

 
2,628,000

Weighted-average ceiling price ($/Bbl)
 
$
95.51

 
$
88.18

 
$
97.22

Total volume hedged with floor price (Bbl)
 
1,923,880

 
5,227,800

 
2,628,000

Weighted-average floor price ($/Bbl)
 
$
80.99

 
$
77.25

 
$
77.22

Basis swaps:(2)
 
 
 
 
 
 
Hedged volume (Bbl)
 
920,000

 
—

 
—

Weighted-average price ($/Bbl)
 
$
(1.95
)
 
$
—

 
$
—

Natural gas positions:(3)
 
 

 
 

 
 

Collars:
 
 

 
 

 
 

Hedged volume (MMBtu)
 
7,192,000

 
18,666,000

 
5,475,000

Weighted-average floor price ($/MMBtu)
 
$
3.00

 
$
3.00

 
$
3.00

Weighted-average ceiling price ($/MMBtu)
 
$
5.96

 
$
5.60

 
$
4.00

_______________________________________________________________________________
(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 ("WTI NYMEX").
(2)
The associated oil basis swaps are settled on the differential between the WTI Midland and the WTI NYMEX index oil prices.
(3)
Natural gas derivatives are settled based on the Inside FERC index price for West Texas Waha for the calculation period.
b. Balance sheet presentation
In accordance with the Company's standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives. The Company's oil and natural gas commodity derivatives are presented on a net

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

basis as "Derivatives" on the unaudited consolidated balance sheets. See Note 9.a for a summary of the fair value of derivatives on a gross basis.
By using derivatives to hedge exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk. For the Company, market risk is the exposure to changes in the market price of oil and natural gas, which are subject to fluctuations from a variety of factors, including changes in supply and demand. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, thereby creating credit risk. The Company's counterparties are participants in the Senior Secured Credit Facility, which is secured by the Company's oil and natural gas reserves; therefore, the Company is not required to post any collateral. The Company does not require collateral from its derivative counterparties. The Company minimizes the credit risk in derivatives by: (i) limiting its exposure to any single counterparty, (ii) entering into derivatives only with counterparties that meet the Company's minimum credit quality standard or have a guarantee from an affiliate that meets the Company's minimum credit quality standard and (iii) monitoring the creditworthiness of the Company's counterparties on an ongoing basis.
Note 9—Fair value measurements
The Company accounts for its oil and natural gas commodity derivatives at fair value. The fair value of derivatives is determined utilizing pricing models for similar instruments. The models use a variety of techniques to arrive at fair value, including quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward curves generated from a compilation of data gathered from third parties.
The Company has categorized its assets and liabilities measured at fair value, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).
Assets and liabilities recorded at fair value on the unaudited consolidated balance sheets are categorized based on inputs to the valuation techniques as follows: 
Level 1—
Assets and liabilities recorded at fair value for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access. Active markets are considered to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
 
 
Level 2—
Assets and liabilities recorded at fair value for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the assets or liabilities. Substantially all of these inputs are observable in the marketplace throughout the full term of the price risk management instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace.
 
 
Level 3—
Assets and liabilities recorded at fair value for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. Unobservable inputs are not corroborated by market data. These inputs reflect management's own assumptions about the assumptions a market participant would use in pricing the asset or liability.
When the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety. The Company conducts a review of fair value hierarchy classifications on an annual basis. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities. Transfers between fair value hierarchy levels are recognized and reported in the period in which the transfer occurred. No transfers between fair value hierarchy levels occurred during the three or nine months ended September 30, 2015 or 2014.

22
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)

a. Fair value measurement on a recurring basis
The following tables summarize the Company's fair value hierarchy by commodity on a gross basis and the net presentation on the unaudited consolidated balance sheets for derivative assets and liabilities measured at fair value on a recurring basis for the periods presented:
(in thousands)
 
Level 1
 
Level 2
 
Level 3
 
Total gross fair value
 
Amounts offset
 
Net fair value presented on the consolidated balance sheets
As of September 30, 2015:
 
 
 
 
 
 
 
 
 
 
 
 
Assets
 
 
 
 
 
 
 
 
 
 
 
 
Current:
 
 
 
 
 
 
 
 
 
 
 
 
Oil derivatives
 
$
—

 
$
180,141

 
$
—

 
$
180,141

 
$
(1,805
)
 
$
178,336

Natural gas derivatives
 
—

 
10,747

 
—

 
10,747

 
—

 
10,747

Oil deferred premiums
 
—

 
—

 
—

 
—

 
(4,751
)
 
(4,751
)
Natural gas deferred premiums
 
—

 
—

 
—

 
—

 
(175
)
 
(175
)
Noncurrent:
 
 
 
 
 
 
 
 
 
 
 
 
Oil derivatives
 
$
—

 
$
100,594

 
$
—

 
$
100,594

 
$
—

 
$
100,594

Natural gas derivatives
 
—

 
3,659

 
—

 
3,659

 
—

 
3,659

Oil deferred premiums
 
—

 
—

 
—

 
—

 
(5,964
)
 
(5,964
)
Natural gas deferred premiums
 
—

 
—

 
—

 
—

 
(439
)
 
(439
)
Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
Current:
 
 
 
 
 
 
 
 
 
 
 
 
Oil derivatives
 
$
—

 
$
(1,805
)
 
$
—

 
$
(1,805
)
 
$
1,805

 
$
—

Natural gas derivatives
 
—

 
—

 
—

 
—

 
—

 
—

Oil deferred premiums
 
—

 
—

 
(4,751
)
 
(4,751
)
 
4,751

 
—

Natural gas deferred premiums
 
—

 
—

 
(175
)
 
(175
)
 
175

 
—

Noncurrent:
 
 
 
 
 
 
 
 
 
 
 
 
Oil derivatives
 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

Natural gas derivatives
 
—

 
—

 
—

 
—

 
—

 
—

Oil deferred premiums
 
—

 
—

 
(5,964
)
 
(5,964
)
 
5,964

 
—

Natural gas deferred premiums
 
—

 
—

 
(439
)
 
(439
)
 
439

 
—

Net derivative position
 
$
—

 
$
293,336

 
$
(11,329
)
 
$
282,007

 
$
—

 
$
282,007


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

(in thousands)
 
Level 1
 
Level 2
 
Level 3
 
Total gross fair value
 
Amounts offset
 
Net fair value presented on the consolidated balance sheets
As of December 31, 2014:
 
 
 
 
 
 
 
 
 
 
 
 
Assets
 
 
 
 
 
 
 
 
 
 
 
 
Current:
 
 
 
 
 
 
 
 
 
 
 
 
Oil derivatives
 
$
—

 
$
190,303

 
$
—

 
$
190,303

 
$
—

 
$
190,303

Natural gas derivatives
 
—

 
9,647

 
—

 
9,647

 
—

 
9,647

Oil deferred premiums
 
—

 
—

 
—

 
—

 
(4,653
)
 
(4,653
)
Natural gas deferred premiums
 
—

 
—

 
—

 
—

 
(696
)
 
(696
)
Noncurrent:
 
 
 
 
 
 
 
 
 
 
 
 
Oil derivatives
 
$
—

 
$
117,963

 
$
—

 
$
117,963

 
$
—

 
$
117,963

Natural gas derivatives
 
—

 
3,646

 
—

 
3,646

 
—

 
3,646

Oil deferred premiums
 
—

 
—

 
—

 
—

 
(3,821
)
 
(3,821
)
Natural gas deferred premiums
 
—

 
—

 
—

 
—

 
—

 
—

Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
Current:
 
 
 
 
 
 
 
 
 
 
 
 
Oil derivatives
 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

Natural gas derivatives
 
—

 
—

 
—

 
—

 
—

 
—

Oil deferred premiums
 
—

 
—

 
(4,768
)
 
(4,768
)
 
4,653

 
(115
)
Natural gas deferred premiums
 
—

 
—

 
(696
)
 
(696
)
 
696

 
—

Noncurrent:
 
 
 
 
 
 
 
 
 
 
 
 
Oil derivatives
 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

Natural gas derivatives
 
—

 
—

 
—

 
—

 
—

 
—

Oil deferred premiums
 
—

 
—

 
(3,821
)
 
(3,821
)
 
3,821

 
—

Natural gas deferred premiums
 
—

 
—

 
—

 
—

 
—

 
—

Net derivative position
 
$
—

 
$
321,559

 
$
(9,285
)
 
$
312,274

 
$
—

 
$
312,274

These items are included as "Derivatives" on the unaudited consolidated balance sheets. Significant Level 2 assumptions associated with the calculation of discounted cash flows used in the mark-to-market analysis of commodity derivatives include each derivative contract's corresponding commodity index price, appropriate risk-adjusted discount rates and other relevant data.
The Company's deferred premiums associated with its 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 premium is not adjusted; therefore, significant increases (decreases) in the Senior Secured Credit Facility rate would result in a significantly lower (higher) fair value measurement for each new contract entered into that contained a deferred premium; however, the valuation for the deferred premiums already recorded would remain unaffected. While the Company believes the sources utilized to arrive at the fair value estimates are reliable, different sources or methods could have yielded different fair value estimates; therefore, on a quarterly basis, the valuation is compared to counterparty valuations and a third-party valuation of the deferred premiums for reasonableness.

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

The following table presents actual cash payments required for deferred premiums as of September 30, 2015, and for the calendar years following:
(in thousands)
 
 
Remaining 2015
 
$
1,249

2016
 
4,471

2017
 
5,418

2018
 
426

  Total
 
$
11,564

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)

2015
 
2014
 
2015
 
2014
Balance of Level 3 at beginning of period

$
(12,087
)
 
$
(9,025
)
 
$
(9,285
)

$
(12,684
)
Change in net present value of deferred premiums for derivatives

(53
)
 
(50
)
 
(141
)

(170
)
Total purchases and settlements:

 
 
 
 
 



Purchases

(437
)
 
(3,800
)
 
(5,821
)

(3,800
)
Settlements

1,248

 
1,820

 
3,918


5,599

Balance of Level 3 at end of period

$
(11,329
)
 
$
(11,055
)
 
$
(11,329
)

$
(11,055
)
b. Fair value measurement on a nonrecurring basis
The Company accounts for the impairment of long-lived assets, if any, at fair value on a nonrecurring basis. For purposes of fair value measurement, it was determined that the impairment of long-lived assets is classified as Level 3, based on the use of internally developed cash flow models. See Note 2.m for discussion regarding the Company's impairment of line-fill during the three months ended September 30, 2015 and impairments of materials and supplies and line-fill during the nine months ended September 30, 2015.
The accounting policies for impairment of oil and natural gas properties are discussed in Note 2.f. Significant inputs included in the calculation of discounted cash flows used in the impairment analysis include the Company's estimate of operating and development costs, anticipated production of evaluated reserves and other relevant data. See Note 2.f for discussion regarding the Company's second and third-quarter full cost ceiling impairments.
Note 10—Credit risk
The Company's oil, NGL and natural gas sales are made to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. The Company's joint operations accounts receivable are from a number of oil and natural gas companies, partnerships, individuals and others who own interests in the oil and natural gas properties operated by the Company. 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. These transactions expose the Company to potential credit risk from its counterparties. In accordance with the Company's standard practice, its derivatives are subject to counterparty netting under agreements governing such derivatives; therefore, the credit risk associated with its derivative counterparties is somewhat mitigated. See Notes 2.e, 8 and 9 for additional information regarding the Company's derivatives.
Note 11—Commitments and contingencies
a.    Litigation

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

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


b.    Drilling contracts

The Company has committed to drilling contracts with various third parties to complete its various drilling projects. The contracts contain early termination clauses that require the Company to potentially pay penalties to the third parties should the Company cease drilling efforts. These penalties would negatively impact the Company's financial statements upon early contract termination, especially if a significant number of such contracts were terminated early in their respective terms. In the fourth quarter of 2014, the Company announced a reduced 2015 capital expenditure budget compared to 2014. As a result, the Company began releasing rigs as drilling contracts came close to expiration and incurred charges of $0.5 million in the fourth quarter of 2014. No comparable amounts were recorded in the three and nine months ended September 30, 2015 or 2014. Future commitments of $18.4 million as of September 30, 2015 are not recorded in the accompanying unaudited consolidated balance sheets. Management does not currently anticipate the early termination of any existing contracts in 2015 that would result in a substantial penalty.
 
c.    Federal and state regulations

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

See Notes 2.h, 15.a and 19.a for the amount of and discussion regarding the commitments to the Company's non-consolidated variable interest entity ("VIE").
Note 12—Restructuring
Following the fourth-quarter 2014 drop in oil prices, in an effort to reduce costs and to better position the Company for ongoing efficient growth, on January 20, 2015, the Company executed a company-wide restructuring and reduction in force (the "RIF") that included (i) the relocation of certain employees in the Company's Dallas, Texas area office to the Company's other existing offices in Tulsa, Oklahoma and Midland, Texas; (ii) closing the Company's Dallas, Texas area office; (iii) a workforce reduction of approximately 75 employees and (iv) the release of 24 contract personnel. The RIF was communicated to employees on January 20, 2015 and was generally effective immediately. The Company's compensation committee approved the RIF and the related severance package. The Company incurred $6.0 million in expenses during the nine months ended September 30, 2015 related to the RIF.
Note 13—Net income (loss) per share
Basic net income (loss) per share is computed by dividing net income (loss) by the weighted-average number of common shares outstanding for the period. Diluted net income (loss) per 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, 2015, all of these potentially dilutive items were anti-dilutive due to the Company's net loss and, therefore, were excluded from the calculation of diluted net income (loss) per share.
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 effects of the Company's then outstanding (i) restricted stock options that were granted in February 2014 to purchase 336,140 shares of common stock at $25.60 per share and (ii) 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"), were excluded from the calculation of diluted net income per share for the three and nine months ended September 30, 2014 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.
    

26
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 (loss) per share for the periods presented:
 
 
Three months ended September 30,
 
Nine months ended September 30,
(in thousands, except for per share data)
 
2015
 
2014
 
2015
 
2014
Net income (loss) (numerator):
 
 
 
 
 
 

 
 

Net income (loss)—basic and diluted
 
$
(847,783
)
 
$
83,407

 
$
(1,245,289
)
 
$
64,295

Weighted-average common shares outstanding (denominator)(1):
 
 
 
 
 
 
 
 
Basic
 
211,204


141,413

 
195,081

 
141,261

Non-vested restricted stock awards
 
—

 
2,334

 
—

 
2,246

Outstanding restricted stock options(2) 
 
—

 
66

 
—

 
76

Diluted
 
211,204


143,813

 
195,081

 
143,583

Net income (loss) per share:
 
 
 
 
 
 
 
 

Basic
 
$
(4.01
)
 
$
0.59

 
$
(6.38
)
 
$
0.46

Diluted
 
$
(4.01
)
 
$
0.58

 
$
(6.38
)
 
$
0.45

______________________________________________________________________________
(1)
For the three and nine months ended September 30, 2015, weighted-average common shares outstanding used in the computation of basic and diluted net loss per share attributable to stockholders has been computed taking into account the March 2015 Equity Offering.
(2)
For the three and nine months ended September 30, 2014, the dilutive effect of the Company's then outstanding options that were granted in February 2013 to purchase 780,281 shares of common stock at $17.34 per share was calculated utilizing the treasury stock method.
Note 14—Variable interest entity
An entity is referred to as a 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.
LMS contributed $48.5 million and $63.0 million during the three and nine months ended September 30, 2015, respectively, and $18.1 million and $37.6 million during the three and nine months ended September 30, 2014, respectively, to Medallion Gathering & Processing, LLC, a Texas limited liability company formed on October 12, 2012, and its wholly-owned subsidiaries (together "Medallion"). See Note 19.a for discussion on a contribution made to Medallion subsequent to September 30, 2015.
LMS holds 49% of Medallion ownership units. Medallion was established for the purpose of developing midstream solutions and providing midstream infrastructure to bring oil, NGL and natural gas to market. LMS 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, LMS is not considered to be the primary beneficiary of the VIE because LMS does not have the power to direct the activities that most significantly affect Medallion's economic performance. As such, Medallion is accounted for under the equity method of accounting with the Company's proportionate share of Medallion's net income (loss) reflected in the unaudited consolidated statements of operations as "Income (loss) from equity method investee" and the carrying amount reflected in the unaudited consolidated balance sheets as "Investment in equity method investee."

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

During the nine months ended September 30, 2015, Medallion continued expansion activities on existing portions of its pipeline infrastructure in order to gather additional third-party oil production and began recognizing revenue due to its main pipeline becoming fully operational. See Note 15.a for discussion of items included in the unaudited consolidated financial statements related to Medallion.
During the nine months ended September 30, 2015, the Company negotiated a buyout of a minimum volume commitment to Medallion, which was related to natural gas gathering infrastructure Medallion constructed on acreage that the Company does not plan to develop. The portion of the buyout that was related to the Company's minimum volume commitment for future periods was $3.0 million and is included in the unaudited consolidated statements of operations in the line item "Minimum volume commitments" for the period in which the buyout was settled.
Note 15—Related Parties
a.    Medallion
The following table summarizes items included in the unaudited consolidated statements of operations related to Medallion for the periods presented:
 
 
Three months ended September 30,
 
Nine months ended September 30,
(in thousands)
 
2015
 
2014
 
2015
 
2014
Midstream service revenues
 
$
—

 
$
—

 
$
487

 
$
—

Minimum volume commitments
 
—

 
675

 
5,235

 
1,779

Interest and other income
 
50

 
—

 
158

 
—

The following table summarizes items included in the unaudited consolidated balance sheets related to Medallion for the periods presented:
(in thousands)
 
September 30, 2015
 
December 31, 2014
Other assets, net
 
$
1,269

 
$
1,110

Other current liabilities
 
34,322

 
3,443

Amounts included in "Other assets, net" above represent LMS owned line-fill in Medallion's pipeline and amounts included in "Other current liabilities" above represent LMS's capital contribution payable to Medallion, of which a portion was paid subsequent to September 30, 2015. See Note 14 for additional discussion of Medallion and Note 19.a for additional discussion of the subsequent payment to Medallion.
b.    Targa Resources Corp.
The Company has a gathering and processing arrangement with affiliates of Targa Resources Corp. ("Targa"). One of Laredo's directors is on the board of directors of Targa.
The following table summarizes the net oil, NGL and natural gas sales (oil, NGL and natural gas sales less production taxes) received from Targa and included in the unaudited consolidated statements of operations for the periods presented:
 
 
Three months ended September 30,
 
Nine months ended September 30,
(in thousands)
 
2015
 
2014
 
2015
 
2014
Oil, NGL and natural gas sales
 
$
23,540

 
$
24,148

 
$
77,183

 
$
70,624

The following table summarizes the amounts included in oil, NGL and natural gas sales receivable from Targa in the unaudited consolidated balance sheets for the periods presented:
(in thousands)
 
September 30, 2015
 
December 31, 2014
Accounts receivable, net
 
$
7,138

 
$
12,869

Note 16—Segments
Since the beginning of 2015, the Company has presented financial results by segment to highlight the growing value of its midstream and marketing segment and its interest in Medallion, as Medallion's third-party revenues increase.

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

The Company operates in two business segments, which are (i) exploration and production and (ii) midstream and marketing. The exploration and production segment is engaged in the acquisition, exploration and development of oil and natural gas properties. The midstream and marketing segment provides Laredo's exploration and production segment and certain third parties with (i) any products and services that need to be delivered by midstream infrastructure, including oil and natural gas gathering services as well as rig fuel, natural gas lift and water in Laredo's primary drilling corridors and (ii) takeaway optionality in the field and firm service commitments to maximize Laredo's oil, NGL and natural gas revenues.
    

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

The following tables present selected financial information regarding the Company's operating segments for the periods presented:
(in thousands)
 
Exploration and production
 
Midstream and marketing
 

Eliminations
 
Consolidated
company
Three months ended September 30, 2015:
 
 
 
 
 
 
 
 
Oil, NGL and natural gas sales
 
$
105,025

 
$
753

 
$
(1,171
)
 
$
104,607

Midstream service revenues
 
—

 
7,917

 
(6,044
)
 
1,873

Sales of purchased oil
 
—

 
43,860

 
—

 
43,860

Total revenues
 
105,025

 
52,530

 
(7,215
)
 
150,340

Lease operating expenses, including production tax
 
35,531

 
—

 
(2,524
)
 
33,007

Midstream service expenses
 
—

 
5,240

 
(4,148
)
 
1,092

Costs of purchased oil
 
—

 
46,961

 
—

 
46,961

General and administrative(1)
 
20,713

 
2,200

 
—

 
22,913

Depletion, depreciation and amortization(2)
 
64,664

 
2,113

 
—

 
66,777

Other operating costs and expenses(3)
 
906,968

 
481

 
—

 
907,449

Operating loss
 
$
(922,851
)
 
$
(4,465
)
 
$
(543
)
 
$
(927,859
)
Other financial information:
 
 
 
 
 
 
 
 
Income from equity method investee
 
$
—

 
$
2,104

 
$
—

 
$
2,104

Interest expense(4)
 
$
(22,030
)
 
$
(1,318
)
 
$
—

 
$
(23,348
)
Capital expenditures
 
$
(117,962
)
 
$
(979
)
 
$
—

 
$
(118,941
)
Gross property and equipment(5)
 
$
5,178,245

 
$
314,138

 
$
(908
)
 
$
5,491,475

Three months ended September 30, 2014:
 
 
 
 
 
 
 
 
Oil, NGL and natural gas sales
 
$
199,968

 
$
619

 
$
(1,097
)
 
$
199,490

Midstream service revenues
 
—

 
1,875

 
(1,124
)
 
751

Total revenues
 
199,968

 
2,494

 
(2,221
)
 
200,241

Lease operating expenses, including production tax
 
39,218

 
—

 
(1,503
)
 
37,715

Midstream service expenses, including minimum volume commitments
 
—

 
2,519

 
(619
)
 
1,900

General and administrative(1)
 
25,145

 
1,933

 
—

 
27,078

Depletion, depreciation and amortization(2)
 
62,298

 
1,644

 
—

 
63,942

Other operating costs and expenses(3)
 
414

 
28

 
—

 
442

Operating income (loss)
 
$
72,893

 
$
(3,630
)
 
$
(99
)
 
$
69,164

Other financial information:
 
 
 
 
 
 
 
 
Loss from equity method investee
 
$
—

 
$
(61
)
 
$
—

 
$
(61
)
Interest expense(4)
 
$
(29,584
)
 
$
(965
)
 
$
—

 
$
(30,549
)
Capital expenditures
 
$
(518,388
)
 
$
(19,052
)
 
$
—

 
$
(537,440
)
Gross property and equipment(5)
 
$
4,489,599

 
$
146,483

 
$
(99
)
 
$
4,635,983

_______________________________________________________________________________
(1)
General and administrative costs were allocated based on the number of employees in the respective segment as of September 30, 2015 and 2014. However, payroll, deferred compensation, vehicle costs and the capitalization of payroll and deferred compensation associated with land and geology, which are components of general and administrative, are based on actual costs for each segment for the three months ended September 30, 2015 and 2014.
(2)
Depletion, depreciation and amortization is based on actual costs for each segment with the exception of the allocation of other fixed assets, which is based on the number of employees in the respective segment as of September 30, 2015 and 2014.
(3)
Includes accretion of asset retirement obligations and impairments for the three months ended September 30, 2015 and accretion of asset retirement obligations for the three months ended September 30, 2014. These expenses are based on actual costs and are not allocated. See Notes 2.f and 2.m for discussion of the Company's impairments.
(4)
Interest expense is allocated based on gross property and equipment and total contributions to the Company's equity method investee as of September 30, 2015 and 2014.
(5)
Gross property and equipment includes investment in equity method investee totaling $160.2 million and $40.8 million as of September 30, 2015 and 2014, respectively. Other fixed assets were allocated based on the number of employees in the respective segment as of September 30, 2015 and 2014.

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

(in thousands)
 
Exploration and production
 
Midstream and marketing
 
Eliminations
 
Consolidated
company
Nine months ended September 30, 2015:
 
 
 
 
 
 
 
 
Oil, NGL and natural gas sales
 
$
348,915


$
1,086


$
(1,722
)
 
$
348,279

Midstream service revenues
 
—


15,962


(11,054
)
 
4,908

Sales of purchased oil
 
—


130,178


—

 
130,178

Total revenues
 
348,915

 
147,226

 
(12,776
)
 
483,365

Lease operating expenses, including production tax
 
120,799


—


(7,620
)
 
113,179

Midstream service expenses, including minimum volume commitments
 
4,399


9,580


(4,481
)
 
9,498

Costs of purchased oil
 
—


132,578


—

 
132,578

General and administrative(1)
 
61,838


6,138


—

 
67,976

Depletion, depreciation and amortization(2)
 
204,908


5,923


—

 
210,831

Other operating costs and expenses(3)
 
1,404,306


834


—

 
1,405,140

Operating loss
 
$
(1,447,335
)
 
$
(7,827
)
 
$
(675
)
 
$
(1,455,837
)
Other financial information:
 
 
 
 
 
 
 
 
Income from equity method investee
 
$
—


$
4,585


$
—

 
$
4,585

Interest expense(4)
 
$
(75,962
)

$
(3,770
)

$
—

 
$
(79,732
)
Loss on early redemption of debt(4)
 
$
(30,056
)
 
$
(1,481
)
 
$
—

 
$
(31,537
)
Capital expenditures
 
$
(498,834
)

$
(35,293
)

$
—

 
$
(534,127
)
Gross property and equipment(6)
 
$
5,178,245

 
$
314,138

 
$
(908
)
 
$
5,491,475

Nine months ended September 30, 2014:
 
 
 
 
 
 
 
 
Oil, NGL and natural gas sales
 
$
556,054

 
$
619

 
$
(1,097
)
 
$
555,576

Midstream service revenues
 
—

 
4,447

 
(3,428
)
 
1,019

Total revenues
 
556,054

 
5,066

 
(4,525
)
 
556,595

Lease operating expenses, including production tax
 
109,096

 
—

 
(3,807
)
 
105,289

Midstream service expenses, including minimum volume commitments
 
—

 
5,994

 
(619
)
 
5,375

General and administrative(1)
 
79,203

 
5,081

 
—

 
84,284

Depletion, depreciation and amortization(2)
 
163,527

 
3,078

 
—

 
166,605

Other operating costs and expenses(3)
 
1,251

 
28

 
—

 
1,279

Operating income (loss)
 
$
202,977

 
$
(9,115
)
 
$
(99
)
 
$
193,763

Other financial information:
 
 
 
 
 
 
 
 
Loss from equity method investee
 
$
—

 
$
(86
)
 
$
—

 
$
(86
)
Interest expense(4)
 
$
(87,687
)
 
$
(2,505
)
 
$
—

 
$
(90,192
)
Capital expenditures(5)
 
$
(938,719
)
 
$
(45,277
)
 
$
—

 
$
(983,996
)
Gross property and equipment(6)
 
$
4,489,599

 
$
146,483

 
$
(99
)
 
$
4,635,983

_______________________________________________________________________________
(1)
General and administrative costs were allocated based on the number of employees in the respective segment as of September 30, 2015 and 2014. However, payroll, deferred compensation, vehicle costs and the capitalization of payroll and deferred compensation associated with land and geology, which are components of general and administrative, are based on actual costs for each segment for the nine months ended September 30, 2015 and 2014.
(2)
Depletion, depreciation and amortization is based on actual costs for each segment with the exception of the allocation of other fixed assets, which is based on the number of employees in the respective segment as of September 30, 2015 and 2014.
(3)
Includes accretion of asset retirement obligations and impairments for the nine months ended September 30, 2015 and accretion of asset retirement obligations for the nine months ended September 30, 2014. These expenses are based on actual costs and are not allocated. See Notes 2.f and 2.m for discussion of the Company's impairments.
(4)
Interest expense and loss on early redemption of debt are allocated based on gross property and equipment and total contributions to the Company's equity method investee as of September 30, 2015 and 2014.
(5)
Capital expenditures excludes acquisition of mineral interests and acquisition of oil and natural gas properties for the nine months ended September 30, 2014.
(6)
Gross property and equipment includes investment in equity method investee totaling $160.2 million and $40.8 million as of September 30, 2015 and 2014, respectively. Other fixed assets were allocated based on the number of employees in the respective segment as of September 30, 2015 and 2014.

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

Note 17—Subsidiary guarantees
Laredo and the Guarantors have fully and unconditionally guaranteed the January 2022 Notes, the May 2022 Notes, the March 2023 Notes and the Senior Secured Credit Facility, subject to the Releases. In accordance with practices accepted by the SEC, Laredo has prepared condensed consolidating financial statements to quantify the assets, results of operations and cash flows of such subsidiaries as subsidiary guarantors. The following unaudited condensed consolidating balance sheets as of September 30, 2015 and December 31, 2014, unaudited condensed consolidating statements of operations for the three and nine months ended September 30, 2015 and 2014 and unaudited condensed consolidating statements of cash flows for the nine months ended September 30, 2015 and 2014 present financial information for Laredo on a stand-alone basis (carrying any investment in subsidiaries under the equity method), financial information for the subsidiary guarantors on a stand-alone basis (carrying any investment in subsidiaries under the equity method), and the consolidation and elimination entries necessary to arrive at the information for the Company on a condensed consolidated basis. Deferred income taxes for LMS and for GCM are recorded on Laredo's statements of financial position, statements of operations and statements of cash flows as they are disregarded entities for income tax purposes. Laredo and the Guarantors are not restricted from making intercompany distributions to each other.

Condensed consolidating balance sheet
September 30, 2015
(Unaudited)
(in thousands)
 
Laredo
 
Subsidiary Guarantors
 
Intercompany
eliminations
 
Consolidated
company
Accounts receivable, net
 
$
84,918

 
$
15,757

 
$
—

 
$
100,675

Other current assets
 
274,460

 
307

 
—

 
274,767

Total oil and natural gas properties, net
 
1,930,771

 
9,402

 
(908
)
 
1,939,265

Total midstream service assets, net
 
—

 
135,011

 
—

 
135,011

Total other fixed assets, net
 
44,444

 
355

 
—

 
44,799

Investment in subsidiaries and equity method investee
 
267,498

 
160,206

 
(267,498
)
 
160,206

Total other long-term assets
 
173,277

 
4,495

 
—

 
177,772

Total assets
 
$
2,775,368

 
$
325,533

 
$
(268,406
)
 
$
2,832,495

 
 
 
 
 
 
 
 
 
Accounts payable
 
$
23,049

 
$
598

 
$
—

 
$
23,647

Other current liabilities
 
213,178

 
54,724

 
—

 
267,902

Long-term debt, net
 
1,415,566

 
—

 
—

 
1,415,566

Other long-term liabilities
 
33,985

 
2,713

 
—

 
36,698

Stockholders' equity
 
1,089,590

 
267,498

 
(268,406
)
 
1,088,682

Total liabilities and stockholders' equity
 
$
2,775,368

 
$
325,533

 
$
(268,406
)
 
$
2,832,495




32
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)

Condensed consolidating balance sheet
December 31, 2014
(Unaudited)
(in thousands)
 
Laredo
 
Subsidiary Guarantors
 
Intercompany
eliminations
 
Consolidated
company
Accounts receivable, net
 
$
107,860

 
$
19,069

 
$
—

 
$
126,929

Other current assets
 
238,300

 
24

 
—

 
238,324

Total oil and natural gas properties, net
 
3,196,231

 
7,277

 
(233
)
 
3,203,275

Total midstream service assets, net
 
—

 
108,462

 
—

 
108,462

Total other fixed assets, net
 
42,046

 
299

 
—

 
42,345

Investment in subsidiaries and equity method investee
 
163,349

 
58,288

 
(163,349
)
 
58,288

Total other long-term assets
 
128,582

 
4,496

 
—

 
133,078

Total assets
 
$
3,876,368

 
$
197,915

 
$
(163,582
)
 
$
3,910,701

 
 
 
 
 
 
 
 
 
Accounts payable
 
$
38,453

 
$
555

 
$
—

 
$
39,008

Other current liabilities
 
354,217

 
31,800

 
—

 
386,017

Long-term debt, net
 
1,779,447

 
—

 
—

 
1,779,447

Other long-term liabilities
 
140,817

 
2,211

 
—

 
143,028

Stockholders' equity
 
1,563,434

 
163,349

 
(163,582
)
 
1,563,201

Total liabilities and stockholders' equity
 
$
3,876,368

 
$
197,915

 
$
(163,582
)
 
$
3,910,701

 
Condensed consolidating statement of operations
For the three months ended September 30, 2015
(Unaudited)
(in thousands)

Laredo

Subsidiary Guarantors

Intercompany
eliminations

Consolidated
company
Total operating revenues

$
104,920


$
52,635


$
(7,215
)

$
150,340

Total operating costs and expenses

1,030,143


54,728


(6,672
)

1,078,199

Operating loss

(925,223
)

(2,093
)

(543
)

(927,859
)
Interest expense and other, net

(23,256
)

—


—


(23,256
)
Other non-operating income

142,497


2,013


80


144,590

Loss before income taxes

(805,982
)

(80
)

(463
)

(806,525
)
Deferred income tax expense

(41,258
)

—


—


(41,258
)
Net loss

$
(847,240
)

$
(80
)

$
(463
)

$
(847,783
)

Condensed consolidating statement of operations
For the nine months ended September 30, 2015
(Unaudited)

(in thousands)
 
Laredo
 
Subsidiary Guarantors
 
Intercompany
eliminations
 
Consolidated
company
Total operating revenues
 
$
348,753

 
$
147,388

 
$
(12,776
)
 
$
483,365

Total operating costs and expenses
 
1,802,810

 
148,493

 
(12,101
)
 
1,939,202

Operating loss
 
(1,454,057
)
 
(1,105
)
 
(675
)
 
(1,455,837
)
Interest expense and other, net
 
(79,344
)
 
—

 
—

 
(79,344
)
Other non-operating income
 
111,842

 
4,494

 
(3,389
)
 
112,947

Income (loss) before income taxes
 
(1,421,559
)
 
3,389

 
(4,064
)
 
(1,422,234
)
Deferred income tax benefit
 
176,945

 
—

 
—

 
176,945

Net income (loss)
 
$
(1,244,614
)
 
$
3,389

 
$
(4,064
)
 
$
(1,245,289
)

33
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)


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

Operating income (loss)
 
70,906

 
(1,643
)
 
(99
)
 
69,164

Interest expense and other, net
 
(30,516
)
 
—

 
—

 
(30,516
)
Other non-operating income (expense)
 
88,894

 
(157
)
 
1,800

 
90,537

Income (loss) before income taxes
 
129,284

 
(1,800
)
 
1,701

 
129,185

Deferred income tax expense
 
(45,778
)
 
—

 
—

 
(45,778
)
Net income (loss)
 
$
83,506

 
$
(1,800
)
 
$
1,701

 
$
83,407


Condensed consolidating statement of operations
For the nine months ended September 30, 2014
(Unaudited)
(in thousands)
 
Laredo
 
Subsidiary Guarantors
 
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

Operating income (loss)
 
197,886

 
(4,024
)
 
(99
)
 
193,763

Interest expense and other, net
 
(89,882
)
 
—

 
—

 
(89,882
)
Other non-operating expense
 
(8,099
)
 
(234
)
 
4,258

 
(4,075
)
Income (loss) before income taxes
 
99,905

 
(4,258
)
 
4,159

 
99,806

Deferred income tax expense
 
(35,511
)
 
—

 
—

 
(35,511
)
Net income (loss)
 
$
64,394

 
$
(4,258
)
 
$
4,159

 
$
64,295


Condensed consolidating statement of cash flows
For the nine months ended September 30, 2015
(Unaudited)
(in thousands)
 
Laredo
 
Subsidiary Guarantors
 
Intercompany
eliminations
 
Consolidated
company
Net cash flows provided by (used in) operating activities
 
$
229,065

 
$
(172
)
 
$
(3,389
)
 
$
225,504

Change in investments between affiliates
 
(101,858
)
 
98,469

 
3,389

 
—

Capital expenditures and other
 
(433,580
)
 
(98,297
)
 
—

 
(531,877
)
Net cash flows provided by financing activities
 
353,455

 
—

 
—

 
353,455

Net increase in cash and cash equivalents
 
47,082

 
—

 
—

 
47,082

Cash and cash equivalents at beginning of period
 
29,320

 
1

 
—

 
29,321

Cash and cash equivalents at end of period
 
$
76,402

 
$
1

 
$
—

 
$
76,403

 



34
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)

Condensed consolidating statement of cash flows
For the nine months ended September 30, 2014
(Unaudited)
(in thousands)
 
Laredo
 
Subsidiary Guarantors
 
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

Note 18—Recent accounting pronouncements
In July 2015, the Financial Accounting Standards Board ("FASB") issued new guidance in Topic 330, Inventory, which seeks to simplify the measurement of inventory. The amendments in this update apply to inventory that is measured using all methods excluding last-in, first-out and the retail inventory method. The main substantive provision of this guidance is for an entity to change the subsequent measurement of inventory, within the scope of this guidance, from LCM to the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. The amendments in this update are effective for annual reporting periods beginning after December 15, 2016, including interim periods within those fiscal years and should be applied prospectively with earlier application permitted as of the beginning of an interim or annual 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 2015, the FASB issued new guidance in Subtopic 835-30, Interest-Imputation of Interest, which seeks to simplify the presentation of debt issuance costs. These amendments require that debt issuance costs related to a recognized debt liability be presented in an entity's balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this guidance. Entities should apply the amendments on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance. The Company has early-adopted this standard as of September 30, 2015, and has applied its provisions retrospectively. The adoption of this standard resulted in the reclassification of $19.4 million and $21.8 million of unamortized debt issuance costs related to the Company's senior unsecured notes from "Other assets, net" to "Long-term debt, net" within its consolidated balance sheets as of September 30, 2015 and December 31, 2014, respectively. Other than this reclassification, the adoption of this standard did not have an impact on the Company's unaudited consolidated financial statements. The effect of this change in accounting principle on previously reported interim periods are decreases to each of total assets and total liabilities of $26.6 million and $20.1 million as of March 31, 2015 and June 30, 2015, respectively. See Notes 2.g and 5.g for additional discussion of debt issuance costs.
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, 2017, 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.

35
Laredo Petroleum, Inc.
Condensed notes to the consolidated financial statements
(Unaudited)

Note 19—Subsequent events
a.    Medallion capital call
On October 15, 2015, the Company contributed $10.4 million to fund continued expansion activities on existing portions of Medallion's pipeline infrastructure in order to gather additional third-party production. As of September 30, 2015, the Company had recorded a capital contribution payable which included the amount of this capital call. For additional discussion regarding the Senior Secured Credit Facility see Note 5.e.
b.    Senior secured credit facility
On October 30, 2015, in connection with its regular semi-annual redetermination, the Company entered into the Fourth Amendment to the Senior Secured Credit Facility, pursuant to which, among other things, the borrowing base decreased to $1.15 billion, while the maximum credit amount and aggregate elected commitment remained at $2.0 billion and $1.0 billion, respectively, and the amount of “permitted investments” in Medallion increased to $225.0 million in the aggregate at any time.
c.    New commodity derivative contracts
Subsequent to September 30, 2015, the Company entered into the following new commodity derivative contracts:
 
 
Aggregate
volumes
 
Floor price
 
Contract period
Oil (volumes in Bbl):
 
 
 
 
 
 
Put(1)
 
1,296,000

 
$
45.00

 
January 1, 2016 - December 31, 2016
_____________________________________________________________
(1)
The associated commodity derivatives will be settled based on the WTI NYMEX index oil price. A total of $4.5 million in deferred premiums are associated with these contracts.
Note 20—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)
 
2015
 
2014
 
2015
 
2014
Property acquisition costs:
 
 

 
 

 
 

 
—

Evaluated
 
$
—

 
$
—

 
$
—

 
$
3,873

Unevaluated
 
—


—

 
—

 
9,925

Exploration(1)
 
7,803


200,711

 
16,157

 
217,353

Development costs(2)
 
64,451


325,118

 
381,641

 
733,671

Total costs incurred
 
$
72,254


$
525,829

 
$
397,798

 
$
964,822

____________________________________________________________________________
(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 $0.3 million and $1.6 million in asset retirement obligations for the three months ended September 30, 2015 and 2014, respectively, and $1.3 million and $3.1 million for the nine months ended September 30, 2015 and 2014, respectively.


36

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 2014 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 from October 24, 2014, refer to Laredo, LMS and GCM collectively and (ii) when used for historical periods from December 31, 2013 to October 23, 2014, refer to Laredo and LMS collectively, unless the context otherwise indicates or requires. All amounts, dollars and percentages presented in this Quarterly Report are rounded and therefore approximate.
Executive overview
We are an independent energy company focused on the acquisition, exploration and development of oil and natural gas properties in the Permian Basin in West Texas. Since our inception, we have grown primarily through our drilling program coupled with select strategic acquisitions and joint ventures.
Our financial and operating performance for the three months ended September 30, 2015 included the following:
•
Oil, NGL and natural gas sales of $104.6 million, compared to $199.5 million for the three months ended September 30, 2014;
•
Average daily sales volumes of 44,820 BOE/D, compared to 32,970 BOE/D for the three months ended September 30, 2014;
•
Net loss of $847.8 million, including a non-cash full cost ceiling impairment of $906.4 million, compared to net income of $83.4 million for the three months ended September 30, 2014; and
•
Adjusted EBITDA (a non-GAAP financial measure) of $119.8 million, compared to $142.0 million for the three months ended September 30, 2014.
Our financial and operating performance for the nine months ended September 30, 2015 included the following:
•
Oil, NGL and natural gas sales of $348.3 million, compared to $555.6 million for the nine months ended September 30, 2014;
•
Average daily sales volumes of 46,270 BOE/D, compared to 29,577 BOE/D for the nine months ended September 30, 2014;
•
Net loss of $1.25 billion, including a non-cash full cost ceiling impairment of $1.39 billion, compared to net income of $64.3 million for the nine months ended September 30, 2014; and
•
Adjusted EBITDA (a non-GAAP financial measure) of $356.4 million, compared to $447.3 million for the nine months ended September 30, 2014.
Three-stream reporting
As of January 1, 2015, all of our natural gas processing agreements with various processors had been modified to allow us to take title to the NGL resulting from the processing of our natural gas. Based on this, we elected to report reserves, sales volumes, prices and revenues for oil, NGL and natural gas separately for periods after January 1, 2015. This is known as "three-stream reporting." For periods prior to January 1, 2015, we presented our reserves, sales volumes, prices and revenues for oil and natural gas, which combined NGL with the natural gas stream, and did not separately report NGL. This change impacts the comparability of 2015 with prior periods.
Reserves, pricing and non-cash full cost ceiling impairment
Our results of operations are heavily influenced by commodity prices, which historically experience significant fluctuations, have significantly declined and have remained low in recent months. Prices for oil, NGL and natural gas can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for oil, NGL and natural gas, market uncertainty, economic conditions and a variety of additional factors. A continuation of low commodity

37

prices will affect the economic viability of and ability to fund drilling projects, as well as the economic valuation and economic recovery of oil, NGL and natural gas reserves.
Our internal reserves as of September 30, 2015 are reported in three streams: oil, NGL and natural gas. Our reserves as of December 31, 2014 were reported in two streams: oil and liquids-rich natural gas with the economic value of the NGL in our natural gas included in the wellhead natural gas price. The SEC Prices used to value our reserves as of September 30, 2015 were $55.73 per Bbl for oil, $21.87 per Bbl for NGL and $2.89 per MMBtu for natural gas, as of December 31, 2014 were $91.48 per Bbl for oil and $4.25 per MMBtu for liquids-rich natural gas and as of September 30, 2014 were $95.56 per Bbl for oil and $4.16 per MMBtu for liquids-rich natural gas, respectively. The SEC Prices do not include derivative transactions for any period. Primarily, as a result of these lower prices, our internal September 30, 2015 estimated proved reserves decreased 37 MMBOE from our three-stream December 31, 2014 reserves of 297 MMBOE. In order to convert our two-stream December 31, 2014 reserves of 247 MMBOE to three-stream, we utilized actual gas plant economics of 30% shrink and a yield of 127 Bbl of NGL per MMcf. Additionally, using these SEC Prices, our net book value of evaluated oil and natural gas properties exceeded the full cost ceiling amount as of September 30, 2015. As such, we recorded a third-quarter non-cash full cost ceiling impairment of $906.4 million. See Note 2.f to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of this full cost impairment.
We have entered into a number of commodity derivatives, which have enabled us to offset a portion of the changes in our cash flow caused by price fluctuations on our production as discussed in "Item 3. Quantitative and Qualitative Disclosures About Market Risk."
Potential future low commodity price impact on our development plans, reserves and full cost impairment
Oil, NGL and natural gas prices have remained low in the fourth quarter of 2015. If prices remain at or below the current low levels, subject to numerous factors and inherent limitations, we will incur an additional non-cash full cost impairment in the fourth quarter, which will have an adverse effect on our results of operations. Furthermore, at September 30, 2015, as discussed above, we had material reductions in our proved reserves and we will have further reductions at December 31, 2015, due to price-related changes in our proved developed reserves and the potential to modify our development plans for future years as will be determined during the fourth quarter.
There are numerous uncertainties inherent in the estimation of proved reserves and accounting for oil and natural gas properties in future periods. In addition to unknown future commodity prices, other uncertainties include (i) changes in drilling and completion costs, (ii) changes in oilfield service costs, (iii) production results, (iv) our ability, in a low price environment, to strategically drill the most economic locations in our multi-stack horizontal targets, (v) income tax impacts, (vi) potential recognition of additional proved undeveloped reserves, (vii) any potential value added to our proved reserves when testing recoverability from drilling unbooked locations and (viii) the inherent significant volatility in the commodity prices for oil and natural gas recently exemplified by the large swings in recent months.
Each of the above factors is evaluated on a quarterly basis and if there is a material change in any factor it is incorporated into our internal reserve estimation utilized in our quarterly accounting estimates. We use our internal reserve estimates to evaluate, also on a quarterly basis, the reasonableness of our reserve development plans for our reported reserves. Changes in circumstance, including commodity pricing, economic factors and the other uncertainties described above may lead to changes in our reserve development plans.
Although we do not disclose reserve quantities on a quarterly basis, we have set forth below a calculation of a potential future further reduction of our proved reserves. Such implied impairment and decrease in reserves should not be interpreted to be indicative of our development plan or of our actual future results. Each of the uncertainties noted above has been evaluated for material known trends to be potentially included in the estimation of possible fourth-quarter effects. Based on such review, we determined that the impact of decreased commodity prices is the only significant known variable necessary in the following scenario.
Both our hypothetical fourth-quarter full cost ceiling calculation and our hypothetical reserves estimates have been prepared by substituting (i) $45.85 per barrel for oil, (ii) $12.57 per barrel for NGL and (iii) $1.88 per MMBtu for natural gas (the "Pro Forma Prices") for the respective SEC Prices as of September 30, 2015. All other inputs and assumptions have been held constant. Accordingly, this estimation strictly isolates the estimated impact of more current commodity prices on the 2015 year-end SEC Prices that will be utilized in our full cost ceiling calculation and our reserves estimate. The Pro Forma Prices use a slightly modified SEC Price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for oil, NGL and natural gas on the first day of the month for the 11 months ended November 1, 2015, with the price for November 1, 2015 held constant for the remaining twelfth month of the calculation. Based solely on the substitution of the Pro Forma Prices into our September 30, 2015 internal reserve estimates, the implied fourth-quarter impairment would be $535 million and the implied impact to our three-stream December 31, 2014 reserves of 297 MMBOE would be a reduction of 64 MMBOE. We

38

believe that substituting the Pro Forma Prices into our September 30, 2015 internal reserve estimates may help provide users with an understanding of the potential fourth-quarter price impact on our December 31, 2015 full cost ceiling test and in preparing our year-end reserve estimates.
Recent developments
Amendment to the Senior Secured Credit Facility
On October 30, 2015, in connection with our regular semi-annual redetermination, we entered into the Fourth Amendment to the Senior Secured Credit Facility, pursuant to which, among other things, the borrowing base decreased to $1.15 billion, while the maximum credit amount and aggregate elected commitment remained at $2.0 billion and $1.0 billion, respectively, and the amount of “permitted investments” in Medallion increased to $225.0 million in the aggregate at any time. For more information regarding the Fourth Amendment to the Senior Secured Credit Facility, see Notes 5.e and 19.b to our unaudited consolidated financial statements included elsewhere in this Quarterly Report and "Part II, Item 5. Other Information-Item 1.01 Entry into a material definitive agreement" below.
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, 2015, we had assembled 142,895 net acres in the Permian Basin.
Sources of our revenue
Our revenues are primarily derived from the sale of oil, NGL and natural gas and the sale of purchased oil within the continental United States and do not include the effects of derivatives. For the three months ended September 30, 2015, our revenues were comprised of sales of 53% oil, 8% NGL, 9% natural gas, 29% sale of purchased oil and 1% midstream service revenues. For the nine months ended September 30, 2015, our revenues were comprised of sales of 55% oil, 8% NGL, 9% natural gas, 27% sale of purchased oil and 1% midstream service revenues. Our oil, NGL and natural gas revenues may vary significantly from period to period as a result of changes in volumes of production and/or changes in commodity prices. Our midstream service revenues may vary due to the level of services provided to third parties for (i) gathered natural gas, (ii) gas lift fees, (iii) oil throughput fees and (iv) water services. Our sales of purchased oil revenue may vary due to changes in oil prices.


39

Results of operations
Three and nine months ended September 30, 2015 as compared to the three and nine months ended September 30, 2014
Sales volumes, oil, NGL and natural gas revenues and pricing
The following table sets forth information regarding sales volumes, oil, NGL and natural gas revenues and average sales prices per BOE sold, for the periods presented:
 
 
Three months ended September 30,
 
Nine months ended September 30,
 
 
2015
 
2014
 
2015
 
2014
Sales volumes(1):
 
 


 

 
 

 
 

Oil (MBbl)
 
1,844


1,778

 
5,954

 
4,712

NGL (MBbl)
 
1,150

 
—

 
3,234

 
—

Natural gas (MMcf)
 
6,778


7,533

 
20,663

 
20,176

Oil equivalents (MBOE)(2)(3)
 
4,124


3,033

 
12,632

 
8,074

Average daily sales volumes (BOE/D)(3)
 
44,820


32,970

 
46,270

 
29,577

% Oil
 
45
%

59
%
 
47
%
 
58
%
Oil, NGL and natural gas revenues (in thousands)(1):
 



 
 
 

 
 

Oil
 
$
79,084


$
155,829

 
$
268,093

 
$
429,175

NGL
 
11,913

 
—

 
39,181

 
—

Natural gas
 
13,610


43,661

 
41,005

 
126,401

Oil, NGL and natural gas sales
 
$
104,607


$
199,490

 
$
348,279

 
$
555,576

Average sales prices(1):
 



 
 
 

 
 

Oil, realized ($/Bbl)(4)
 
$
42.88


$
87.65

 
$
45.03

 
$
91.09

NGL, realized ($/Bbl)(4)
 
$
10.36


$
—

 
$
12.12

 
$
—

Natural gas, realized ($/Mcf)(4)
 
$
2.01


$
5.80

 
$
1.98

 
$
6.26

Average price, realized ($/BOE)(4)
 
$
25.37


$
65.78

 
$
27.57

 
$
68.80

Oil, hedged ($/Bbl)(5)
 
$
76.74


$
88.86

 
$
72.69

 
$
89.73

NGL, hedged ($/Bbl)(5)
 
$
10.36


$
—

 
$
12.12

 
$
—

Natural gas, hedged ($/Mcf)(5)
 
$
2.37


$
5.87

 
$
2.34

 
$
6.24

Average price, hedged ($/BOE)(5)
 
$
41.11


$
66.66

 
$
41.19

 
$
67.95

________________________________________________________________________
(1)
For periods prior to January 1, 2015, we presented our sales volumes, revenues and average sales prices for oil and natural gas, which combined NGL with the natural gas stream, and did not separately report NGL. This change impacts the comparability of the two periods presented.
(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, NGL and natural gas prices are the actual prices realized at the wellhead after all adjustments for 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.
    

40

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)
 
2015
 
2014
 
2015
 
2014
Cash settlements received (paid) for matured commodity derivatives:
 





 
 
 
 
Oil
 
$
63,510


$
3,745

 
$
168,068

 
$
(1,486
)
Natural gas
 
2,632


786

 
7,811

 
166

Total
 
$
66,142


$
4,531

 
$
175,879

 
$
(1,320
)
Premiums paid attributable to contracts that matured during the respective period:
 





 
 
 
 
Oil
 
$
(1,073
)

$
(1,590
)
 
$
(3,391
)
 
$
(4,908
)
Natural gas
 
(175
)

(230
)
 
(527
)
 
(691
)
Total
 
$
(1,248
)

$
(1,820
)
 
$
(3,918
)
 
$
(5,599
)
 
Changes in prices and volumes caused the following changes to our oil, NGL and natural gas revenues between the three months ended September 30, 2015 and 2014:
(in thousands)
 
Oil
 
NGL
 
Natural gas
 
Total net dollar
effect of change
2014 Revenues
 
$
155,829

 
$
—

 
$
43,661


$
199,490

Effect of changes in price
 
(82,566
)
 
11,909

 
(25,689
)
 
(96,346
)
Effect of changes in volumes
 
5,816

 
—

 
(4,374
)
(1) 
1,442

Other
 
5

 
4

 
12

 
21

2015 Revenues
 
$
79,084

 
$
11,913

 
$
13,610

 
$
104,607

______________________________________________________________________
(1)
For periods prior to January 1, 2015, we presented our sales volumes for oil and natural gas, which combined NGL with the natural gas stream, and did not separately report NGL. This change impacts the comparability of the two periods presented.
Changes in prices and volumes caused the following changes to our oil, NGL and natural gas revenues between the nine months ended September 30, 2015 and 2014:
(in thousands)
 
Oil
 
NGL
 
Natural gas
 
Total net dollar
effect of change
2014 Revenues
 
$
429,175

 
$
—

 
$
126,401

 
$
555,576

Effect of changes in price
 
(274,241
)
 
39,195

 
(88,437
)
 
(323,483
)
Effect of changes in volumes
 
113,153

 
—

 
3,050

(1) 
116,203

Other
 
6

 
(14
)
 
(9
)
 
(17
)
2015 Revenues
 
$
268,093

 
$
39,181

 
$
41,005

 
$
348,279

______________________________________________________________________
(1)
For periods prior to January 1, 2015, we presented our sales volumes for oil and natural gas, which combined NGL with the natural gas stream, and did not separately report NGL. This change impacts the comparability of the two periods presented.
Oil revenue. Our oil revenue is a function of oil production volumes sold and average sales prices received for those volumes. The decrease in oil revenue of $76.7 million, or 49%, for the three months ended September 30, 2015 as compared to the three months ended September 30, 2014, is mainly due to a 51% decrease in average oil prices realized, partially offset by a 4% increase in oil production.
The decrease in oil revenue of $161.1 million, or 38%, for the nine months ended September 30, 2015 as compared to the nine months ended September 30, 2014, is mainly due to a 51% decrease in average oil prices realized, partially offset by a 26% increase in oil production.
NGL and natural gas revenues. On January 1, 2015, we began utilizing three-stream reporting, which impacts the comparability of 2015 with prior periods. Our NGL and natural gas revenues are a function of NGL and natural gas production, volumes sold and average sales prices received for those volumes. The total decrease in NGL and natural gas revenues from the

41

three and nine months ended September 30, 2015 as compared to the periods in 2014, is mainly related to a decrease in average prices realized on our natural gas and NGL production. Stripping out the NGL component from our liquids-rich natural gas results in a lower price received for residue natural gas during the three and nine months ended September 30, 2015 as compared to the same periods in 2014 in which we received revenues from liquids-rich natural gas. The decrease in prices is partially offset by an increase in NGL and natural gas production during the three and nine months ended September 30, 2015 as compared to the same periods in 2014, converted to a three-stream basis.
Costs and expenses
The following table sets forth information regarding costs and expenses and average costs per BOE sold for the periods presented:
 
 
Three months ended September 30,

Nine months ended September 30,
(in thousands except for per BOE sold data)
 
2015

2014

2015

2014
Costs and expenses:
 
 

 
 

 
 

 
 

Lease operating expenses
 
$
25,112

 
$
25,165

 
$
86,698

 
$
67,129

Production and ad valorem taxes
 
7,895

 
12,550

 
26,481

 
38,160

Midstream service expenses
 
1,092

 
1,225

 
4,263

 
3,596

Minimum volume commitments
 
—

 
675

 
5,235

 
1,779

Costs of purchased oil
 
46,961

 
—

 
132,578

 
—

General and administrative(1)
 
22,913

 
27,078

 
67,976

 
84,284

Restructuring expenses
 
—

 
—

 
6,042

 
—

Accretion of asset retirement obligations
 
599

 
442

 
1,771

 
1,279

Depletion, depreciation and amortization
 
66,777

 
63,942

 
210,831

 
166,605

Impairment expense
 
906,850

 
—

 
1,397,327

 
—

Total costs and expenses
 
$
1,078,199

 
$
131,077

 
$
1,939,202

 
$
362,832

Average costs per BOE sold(2):






 
 
 
 
Lease operating expenses

$
6.09


$
8.30


$
6.86


$
8.31

Production and ad valorem taxes
 
1.91

 
4.14

 
2.10

 
4.73

Midstream service expenses
 
0.26

 
0.40

 
0.34

 
0.45

General and administrative(1)
 
5.56


8.93


5.38


10.44

Depletion, depreciation and amortization
 
16.19


21.08


16.69


20.63

Total
 
$
30.01


$
42.85


$
31.37


$
44.56

________________________________________________________________________
(1)
General and administrative includes non-cash stock-based compensation, net of amounts capitalized, of $6.9 million and $6.2 million for the three months ended September 30, 2015 and 2014, respectively, and $17.9 million and $16.9 million for the nine months ended September 30, 2015 and 2014, respectively.
(2)
For periods prior to January 1, 2015, we presented our average costs per BOE sold, which combined NGL with the natural gas stream, and did not separately report NGL. This change impacts the comparability of the two periods presented.
Lease operating expenses. Lease operating expenses, which include workover expenses, remained relatively flat for the three months ended September 30, 2015 as compared to the same period in 2014, and increased by $19.6 million, or 29%, for the nine months ended September 30, 2015 as compared to the same period in 2014. For the nine months ended September 30, 2015 compared to the same period in 2014, the increase is mainly due to increases in our (i) producing wells and (ii) well service and workover expenses.
Production and ad valorem taxes. Production and ad valorem taxes decreased by $4.7 million, or 37%, and $11.7 million, or 31%, for the three and nine months ended September 30, 2015, respectively, compared to the same periods in 2014. This change is mainly due to a decrease in production taxes, which are based on and fluctuate proportionately with our oil, NGL and natural gas revenues, which decreased by $5.5 million and $11.8 million for the three and nine months ended September 30, 2015, respectively, compared to the same periods in 2014 as a result of the corresponding decrease in oil, NGL and natural gas revenues.
    

42


Midstream service expenses. See "—Results of Operations - midstream and marketing" for a discussion of these costs.
Minimum volume commitments. Minimum volume commitments decreased by $0.7 million and increased by $3.5 million for the three and nine months ended September 30, 2015, respectively, compared to the same periods in 2014. These changes are mainly a result of the second-quarter 2015 negotiated buyout of a minimum volume commitment to Medallion, which was related to natural gas gathering infrastructure constructed by Medallion on acreage that we do not plan to develop.
Costs of purchased oil. See "—Results of Operations - midstream and marketing" for a discussion of these costs.
General and administrative ("G&A"). The table below shows the changes in the significant components of G&A expense for the periods presented:
(in thousands)
 
Three months ended September 30, 2015 compared to 2014
 
Nine months ended September 30, 2015 compared to 2014
Changes in G&A:
 
 
 
 
Professional fees
 
$
(1,903
)
 
$
(5,687
)
Salaries, benefits and bonuses, net of amount capitalized
 
(1,873
)
 
(3,924
)
Charitable contributions
 
(43
)
 
(3,205
)
Performance unit awards
 
1,445

 
1,967

Stock-based compensation, net of amount capitalized
 
683

 
1,015

Other
 
(2,474
)

(6,474
)
Total changes in G&A
 
$
(4,165
)
 
$
(16,308
)
G&A expense, excluding stock-based compensation, decreased by $5.0 million, or 24%, and $17.4 million, or 26%, for the three and nine months ended September 30, 2015, respectively, compared to the same periods in 2014. The decreases are primarily due to (i) professional fees paid to a consulting company in the prior period that was engaged to assist us with the optimization of our development operations, (ii) reduced personnel expenses as a result of the RIF which occurred early in the first quarter of 2015 and (iii) our $3.0 million charitable contribution pledge expensed in the prior period, which will be paid in annual installments through 2024.
Stock-based compensation, net of amount capitalized, increased by $0.7 million, or 11%, and $1.0 million, or 6%, for the three and nine months ended September 30, 2015, respectively, compared to the same periods in 2014. These changes are mainly due to the issuance of 631,639 non-qualified restricted stock options to management and 602,501 performance share awards to management during the nine months ended September 30, 2015, compared to the issuance of 336,140 non-qualified restricted stock options to management and 271,667 performance share awards to management in the same period in 2014, partially offset by forfeitures of restricted stock awards and restricted stock options as a result of the RIF.
The fair values for each of our restricted stock awards issued were calculated based on the value of our stock price on the grant date in accordance with GAAP and are being expensed on a straight-line basis over their associated requisite service periods. The fair values for each of our non-qualified restricted stock options awards were determined using a Black-Scholes valuation model in accordance with GAAP and are being expensed on a straight-line basis over their associated four-year requisite service periods.
Our performance share awards are accounted for as equity awards. The fair values of the performance share awards issued were based on a projection of the performance of our stock price relative to a peer group, defined in each performance share awards' agreement, utilizing a forward-looking Monte Carlo simulation. The fair values for each of our performance share awards will not be re-measured after their initial grant-date valuation and are being expensed on a straight-line basis over their associated three-year requisite service periods.
Our performance unit awards, which settle in cash if performance criteria are met, are accounted for as liability awards. The associated expense for these awards increased by $1.4 million and $2.0 million for the three and nine months ended September 30, 2015, respectively, compared to the same periods in 2014. These fluctuations are mainly due to the quarterly re-measurement of the 2013 Performance Unit Awards based on the performance of our stock price relative to the peer group utilized in the forward-looking Monte Carlo simulation. The 2012 Performance Unit Awards performance criteria were satisfied at December 31, 2014, and they were paid at $100 per unit during the first quarter of 2015. This payout did not affect 2015 expense as they were fully accrued at December 31, 2014.

43


    See Notes 2.l and 6 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information regarding our stock and performance based compensation.
Restructuring expenses. Restructuring expenses relate to the first-quarter 2015 RIF which was an effort to reduce costs and better position ourselves for ongoing efficient growth. Restructuring expenses of $6.0 million were incurred in the first quarter of 2015. As of September 30, 2015, no additional RIF expenses are expected to be incurred in 2015. See Note 12 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of the RIF.
Depletion, depreciation and amortization ("DD&A"). The following table provides components of our DD&A expense for the periods presented:
 
 
Three months ended September 30,

Nine months ended September 30,
(in thousands except for per BOE sold data)
 
2015

2014

2015

2014
Depletion of evaluated oil and natural gas properties
 
$
63,167

 
$
61,429

 
$
200,440

 
$
160,126

Depreciation of midstream service assets
 
2,000

 
1,207

 
5,580

 
2,899

Depreciation and amortization of other fixed assets
 
1,610

 
1,306

 
4,811

 
3,580

Total DD&A
 
$
66,777

 
$
63,942

 
$
210,831

 
$
166,605

DD&A per BOE sold
 
$
16.19

 
$
21.08

 
$
16.69

 
$
20.63

DD&A increased by $2.8 million, or 4%, and $44.2 million, or 27%, for the three and nine months ended September 30, 2015, respectively, as compared to the same periods in 2014, mainly due to increases in our production.
Impairment expense. Our net book value of evaluated oil and natural gas properties exceeded the full cost ceiling amount as of September 30, 2015. As a result, we recorded a third-quarter non-cash full cost ceiling impairment of $906.4 million. Additionally, as of June 30, 2015, we recorded a second-quarter non-cash full cost ceiling impairment of $488.0 million. There were no comparable full cost impairments in 2014.
Other less material components of impairment expense are LCM adjustments of $2.3 million for materials and supplies for the nine months ended September 30, 2015, and $0.4 million and $0.5 million for our line-fill for the three and nine months ended September 30, 2015, respectively. There were no comparable impairments in 2014.
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)
 
2015

2014

2015

2014
Non-operating income (expense):
 
 

 
 

 
 

 
 

Gain (loss) on derivatives, net
 
$
142,580

 
$
92,790

 
$
141,836

 
$
(1,447
)
Income (loss) from equity method investee
 
2,104

 
(61
)
 
4,585

 
(86
)
Interest expense
 
(23,348
)
 
(30,549
)
 
(79,732
)
 
(90,192
)
Interest and other income
 
92

 
33

 
388

 
310

Loss on early redemption of debt
 
—

 
—

 
(31,537
)
 
—

Write-off of debt issuance costs
 
—

 
—

 
—

 
(124
)
Loss on disposal of assets, net
 
(94
)
 
(2,192
)
 
(1,937
)
 
(2,418
)
Non-operating income (expense), net
 
$
121,334

 
$
60,021

 
$
33,603

 
$
(93,957
)
Derivatives. The table below shows the changes in the components of gain (loss) on derivatives, net for the periods presented:
(in thousands)
 
Three months ended September 30, 2015 compared to 2014
 
Nine months ended September 30, 2015 compared to 2014
Changes in gain (loss) on derivatives, net:
 
 
 
 
Fair value of derivatives outstanding
 
$
(11,821
)
 
$
42,744

Early terminations of derivatives received
 
—

 
(76,660
)
Cash settlements received for matured derivatives
 
61,611

 
177,199

Total changes in gain (loss) on derivatives, net
 
$
49,790

 
$
143,283


44


The changes in fair value of derivatives outstanding for the three and nine months ended September 30, 2015 compared to the same periods in 2014, are the result of the changing relationship between our contract prices and the associated forward curves used to calculate the fair value of our 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 change in gain (loss) on derivatives, net for the nine months ended September 30, 2015 compared to 2014 was partially offset by the cash received for 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. Net cash settlements received for matured derivatives are based on the cash settlement prices of our matured derivatives compared to the prices specified in the derivative contracts.
See Notes 2.e, 8 and 9 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report and "Item 3. Quantitative and Qualitative Disclosures About Market Risk" for additional information regarding our derivatives.
Income (loss) from equity method investee. Income (loss) from equity method investee increased by $2.2 million and $4.7 million for the three and nine months ended September 30, 2015, respectively, compared to the same periods in 2014. During the nine months ended September 30, 2015, Medallion continued expansion activities on existing portions of its pipeline infrastructure in order to gather additional third-party oil production and Medallion began recognizing revenue due to its main pipeline becoming fully operational.
Interest expense. Interest expense decreased by $7.2 million, or 24%, and 10.5 million, or 12%, for the three and nine months ended September 30, 2015, respectively, compared to the same periods in 2014. The decreases are primarily due to the early-redemption of the January 2019 Notes on April 6, 2015, which are partially offset by the issuance of the March 2023 Notes. The March 2023 Notes, which began accruing interest on March 18, 2015, have both a lower interest rate and a lower principal amount than the January 2019 Notes.
The table below shows the changes in the significant components of interest expense for the periods presented:
(in thousands)
 
Three months ended September 30, 2015 compared to 2014
 
Nine months ended September 30, 2015 compared to 2014
Changes in interest expense:
 
 

 
 

January 2019 Notes
 
$
(13,001
)
 
$
(25,143
)
March 2023 Notes
 
5,408

 
11,667

Senior Secured Credit Facility, net of capitalized interest
 
585

 
2,054

January 2022 Notes
 
—

 
1,477

Other
 
(193
)
 
(515
)
Total changes in interest expense
 
$
(7,201
)
 
$
(10,460
)
Loss on early redemption of debt. During the nine months ended September 30, 2015, we redeemed the entire $550.0 million outstanding principal amount of the January 2019 Notes at a redemption price of 104.750% of the principal amount, plus accrued and unpaid interest up to the Redemption Date. We recognized a loss on extinguishment of $31.5 million related to the difference between the redemption price and the net carrying amount of the January 2019 Notes.
Disposal of assets. Loss on disposal of assets decreased $2.1 million and $0.5 million for three and nine months ended September 30, 2015, respectively, compared to the same periods in 2014 as a result of higher losses related to the sales and write-off of materials and supplies and other fixed assets during 2014 as compared to 2015.
Income tax expense. The fluctuations in net income (loss) before and after income tax benefit are shown in the table below:
 
 
Three months ended September 30,
 
Nine months ended September 30,
(in thousands)
 
2015
 
2014
 
2015
 
2014
Income (loss) before income taxes
 
$
(806,525
)
 
$
129,185

 
$
(1,422,234
)
 
$
99,806

Income tax (expense) benefit
 
(41,258
)
 
(45,778
)
 
176,945

 
(35,511
)
Net income (loss)
 
$
(847,783
)
 
$
83,407

 
$
(1,245,289
)
 
$
64,295

The effective tax rate on income (loss) before income taxes was 35% for the three months ended 2014 and 36% for the nine months ended September 30, 2014, respectively. Our effective tax rate is affected by recurring permanent differences, changes in valuation allowances and discrete items that may occur in any given year but are not consistent from year to year. For each of the three and nine months ended September 30, 2015, we recorded a valuation allowance of $326.2 million for our deferred tax assets due to uncertainty regarding their realization. As such, the effective tax rates on our loss before income taxes

45


for the same periods are not meaningful. No comparable amounts were recorded in the three and nine months ended September 30, 2014.
As of September 30, 2015, we expect the fiscal year 2015 annual effective tax rate, excluding any valuation allowance and 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.
During the three and nine months ended September 30, 2015 and 2014, certain shares related to restricted stock awards vested at times when our stock price was lower than the fair value of those shares on the grant date. 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, for which the related income tax deduction was less than the expense previously recognized for book purposes. There were no stock options exercised during the three and nine months ended September 30, 2015. As a result of these differences in book compensation cost and related tax deduction, the tax impact of these shortfalls increased by $0.3 million and $3.1 million for the three and nine months ended September 30, 2015, respectively, compared to the same periods in 2014.
We utilize a one-pool approach when accounting for the pool of windfall tax benefits in which employees and non-employees are grouped into a single pool. As of September 30, 2015 and 2014, 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 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 the future market price of our stock.

46


Results of operations - midstream and marketing
The following table presents selected financial information regarding our midstream and marketing operating segment for the periods presented:
 
 
Three months ended September 30,
 
Nine months ended September 30,
(in thousands)
 
2015
 
2014
 
2015

2014
Natural gas sales
 
$
753

 
$
619

 
$
1,086

 
$
619

Midstream service revenues
 
7,917

 
1,875

 
15,962

 
4,447

Sales of purchased oil
 
43,860

 
—

 
130,178

 
—

Total revenues
 
52,530

 
2,494

 
147,226

 
5,066

Midstream service expenses, including minimum volume commitments
 
5,240

 
2,519

 
9,580

 
5,994

Costs of purchased oil
 
46,961

 
—

 
132,578

 
—

General and administrative(1)
 
2,200

 
1,933

 
6,138

 
5,081

Depletion, depreciation and amortization(2)
 
2,113

 
1,644

 
5,923

 
3,078

Other operating costs and expenses(3)
 
481

 
28

 
834

 
28

Operating loss
 
$
(4,465
)
 
$
(3,630
)
 
$
(7,827
)
 
$
(9,115
)
Other financial information:
 
 
 
 
 
 
 
 
Income (loss) from equity method investee
 
$
2,104

 
$
(61
)
 
$
4,585

 
$
(86
)
Interest expense(4)
 
$
(1,318
)
 
$
(965
)
 
$
(3,770
)
 
$
(2,505
)
Loss on early redemption of debt(4)
 
$
—

 
$
—

 
$
(1,481
)
 
$
—

_______________________________________________________________________________
(1)
G&A costs were allocated based on the number of employees in the respective segment as of September 30, 2015 and 2014. However, payroll, deferred compensation, vehicle costs and the capitalization of payroll and deferred compensation associated with land and geology, which are components of G&A, are based on actual costs for each segment for the three and nine months ended September 30, 2015 and 2014.
(2)
DD&A is based on actual costs for each segment with the exception of the allocation of other fixed assets, which is based on the number of employees in the respective segment as of September 30, 2015 and 2014.
(3)
Includes the following expenses: restructuring expense, accretion of asset retirement obligations and impairments for the three and nine months ended September 30, 2015 and 2014. These expenses are based on actual costs and are not allocated. See Notes 2.f and 2.m to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for discussion of our impairments.
(4)
Interest expense and loss on early redemption of debt are allocated based on gross property and equipment and total contributions to our equity method investee as of September 30, 2015 and 2014.
Natural gas sales. These revenues are related to our midstream and marketing segment providing our exploration and production segment with processed natural gas for use in the field. The corresponding cost component of these transactions are included in "Midstream service expenses."
Midstream service revenues. Our midstream service revenues from operations increased by $6.0 million and $11.5 million during the three and nine months ended September 30, 2015, respectively, compared to the same periods in 2014. These increases are mainly due to (i) higher volumes of gathered natural gas, (ii) water service revenue that we began recognizing in the third quarter of 2015, (iii) oil throughput fees generated by our oil gathering line which was not operational until July of the comparable periods ended 2014 and (iv) natural gas lift fees generated in our drilling corridors that were not operational until September of the comparable periods ended 2014.
Sales of purchased oil. Sales of purchased oil for the three and nine months ended September 30, 2015 were $43.9 million and $130.2 million, respectively. During the fourth quarter of 2014, we began purchasing oil from producers in West Texas, transporting the product on the Bridgetex Pipeline and selling the product to a third party in the Houston market.
Midstream service expenses, including minimum volume commitments. Midstream service expenses, including minimum volume commitments, increased by $2.7 million and $3.6 million for the three and nine months ended September 30, 2015, respectively, compared to the same periods in 2014. Midstream service expenses represent costs incurred to operate and maintain our (i) oil and natural gas gathering and transportation systems and related facilities, (ii) centralized oil storage tanks,

47


(iii) natural gas lift, rig fuel and centralized compression infrastructure and (iv) water storage, recycling and transportation facilities. The increases are due to continued expansion of the midstream service component of our business.
Costs of purchased oil. Costs of purchased oil for the three and nine months ended September 30, 2015 was $47.0 million and $132.6 million, respectively. These costs include purchasing oil from producers and transporting the purchased oil on the Bridgetex Pipeline to the Houston market.
Income (loss) from equity method investee. We own 49% of the ownership units of Medallion. As such, we account for this investment under the equity method of accounting with our proportionate share of net income (loss) reflected in the unaudited consolidated statements of operations as "Income (loss) from equity method investee" and the carrying amount reflected in the unaudited consolidated balance sheets as "Investment in equity method investee." See Note 14 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information regarding this investment. During the nine months ended September 30, 2015, Medallion began recognizing revenue due to its main pipeline becoming fully operational.
Interest expense. Interest expense increased by $0.4 million and $1.3 million during the three and nine months ended September 30, 2015, respectively, compared to the same period in 2014. Interest is allocated to the midstream and marketing segment based on its gross property and equipment and total contributions to its equity method investee. We have expanded the midstream and marketing component of our business and built out our service facilities significantly in the past year, thereby increasing the interest expense that is allocated to this segment.
Loss on early redemption of debt. We recognized a loss on extinguishment related to the difference between the redemption price and the net carrying amount of the extinguished January 2019 Notes during the nine months ended September 30, 2015. Loss on early redemption of debt is allocated to the midstream and marketing segment based on its gross property and equipment and total contributions to its equity method investee.
Liquidity and capital resources
Our primary sources of liquidity have been cash flows from operations, proceeds from equity offerings, proceeds from senior unsecured note offerings and borrowings under our Senior Secured Credit Facility. We believe cash flows from operations and availability under our Senior Secured Credit Facility provide sufficient liquidity to manage our cash needs and contractual obligations and to fund expected capital expenditures. A significant portion of our capital expenditures can be adjusted and managed by us. As we pursue reserves and the economic development of production in the Permian Basin, we continually monitor and 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 operational uses of capital have been for the acquisition, exploration and development of oil and natural gas properties, LMS's infrastructure development and investments in Medallion, our equity method investee.
We continually seek to maintain a financial profile that provides operational flexibility. However, the decrease in oil, NGL and natural gas prices may have a negative impact on our ability to raise additional capital and/or maintain our desired levels of liquidity. As of September 30, 2015, we had $865.0 million available for borrowings under our Senior Secured Credit Facility. We believe that our operating cash flow and the aforementioned liquidity sources combined with our capital budget for 2015 provide us with the financial resources to implement our planned exploration and development activities. We use derivatives to reduce exposure to fluctuations in the prices of oil and natural gas. As of November 2, 2015, approximately 100% of our anticipated oil production for the last three months of 2015 is hedged at a weighted-average floor price of $80.99 per Bbl and approximately 60% of our anticipated natural gas and NGL production for the last three months of 2015 is hedged at a weighted-average floor price of $3.00 per MMBtu.
    

48


The following table summarizes our hedge positions that were in place for the calender years presented:
 
 
Year
2015
 
Year
2016(1)
 
Year
2017
Oil positions(2):
 
 

 
 
 
 

Total volume hedged with floor price (Bbl)
 
7,685,020

 
6,523,800

 
2,628,000

Weighted-average floor price ($/Bbl)
 
$
80.99

 
$
70.84

 
$
77.22

Natural gas positions(3):
 
 

 
 

 
 

Total volume hedged with floor price (MMBtu)
 
28,600,000

 
18,666,000

 
5,475,000

Weighted-average floor price ($/MMBtu)
 
$
3.00

 
$
3.00

 
$
3.00

_______________________________________________________________________________
(1)
Includes derivatives entered into subsequent to September 30, 2015.
(2)
Oil derivatives are settled based on the WTI NYMEX index oil prices.
(3)
Natural gas derivatives are settled based on the Inside FERC index price for West Texas Waha for the calculation period.
By removing a significant portion of the price volatility associated with future production, we expect to mitigate, but not eliminate, the potential effects of variability in cash flows from operations due to fluctuations in commodity prices.
On September 15, 2015, we completed the sale of non-strategic and primarily non-operated properties and associated production totaling 6,060 net acres and 123 producing properties in the Midland Basin to a third-party buyer for a sales price of $65.5 million. After transaction costs and adjustments at closing reflecting an economic effective date of July 1, 2015, the net proceeds were $65.2 million, net of working capital adjustments and subject to post-closing cost adjustments.
On March 5, 2015, we completed the sale of 69,000,000 shares of Laredo's common stock at a price to the public of $11.05 per share, from which we received net proceeds of $754.2 million after underwriting discounts, commissions and offering expenses. Entities affiliated with Warburg Pincus purchased 29,800,000 shares in the March 2015 Equity Offering, following which Warburg Pincus owned 41.0% of our common stock.
On March 18, 2015, we completed an offering of $350.0 million in aggregate principal amount of 6 1/4% senior unsecured notes due 2023, which will mature on March 15, 2023 and bear an interest rate of 6 1/4% per annum payable semi-annually in cash in arrears on March 15 and September 15 of each year, commencing September 15, 2015.
As of September 30, 2015, we had $135.0 million outstanding under our Senior Secured Credit Facility and $1.3 billion in senior unsecured notes. We had $865.0 million available for borrowings under our Senior Secured Credit Facility and $76.4 million in cash on hand for total available liquidity of $941.4 million as of September 30, 2015.
As of November 3, 2015 we had $1.4 billion in debt outstanding, $865.0 million available for borrowings under our Senior Secured Credit Facility and $50.9 million in cash on hand for total available liquidity of $915.9 million.
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. See "Item 3. Quantitative and Qualitative Disclosures About Market Risk" below.
Cash flows
Our cash flows for the periods presented are as follows:
 
 
Nine months ended September 30,
(in thousands)
 
2015
 
2014
Net cash provided by operating activities
 
$
225,504

 
$
376,336

Net cash used in investing activities
 
(531,877
)
 
(1,033,748
)
Net cash provided by financing activities
 
353,455

 
515,019

Net increase (decrease) in cash and cash equivalents
 
$
47,082

 
$
(142,393
)

49


Cash flows provided by operating activities
Net cash provided by operating activities was $225.5 million and $376.3 million for the nine months ended September 30, 2015 and 2014, respectively. The decrease of $150.8 million was largely due to the $76.7 million net proceeds received for early terminations of commodity derivative contracts during the nine months ended September 30, 2014. Other notable changes in net cash provided by operating activities were (i) increases of $1.31 billion in net loss and $212.5 million in deferred income tax benefit, (ii) an increase of $143.3 million in gain on derivatives, net and (iii) a $53.8 million reduction in working capital. These changes were partially offset by (i) an increase of $1.40 billion in impairment expense during the nine months ended September 30, 2015, (ii) an increase of $177.2 million in cash settlements received for matured derivatives, net, (iii) an increase of $44.2 million in depletion, depreciation and amortization expense and (iv) a $31.5 million loss on early redemption of debt during the nine months ended September 30, 2015.
Our operating cash flows are sensitive to a number of variables, the most significant of which are the volatility of oil, NGL and natural gas prices and production levels. Regional and worldwide economic activity, weather, infrastructure, capacity to reach markets, costs of operations and other variable factors significantly impact the prices of these commodities. These factors are not within our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see "Item 3. Quantitative and Qualitative Disclosures About Market Risk."
Cash flows used in investing activities
Net cash used in investing activities was $531.9 million and $1.03 billion for the nine months ended September 30, 2015 and 2014, respectively. The decrease of $501.9 million is mainly attributable to a $434.8 million decrease in capital expenditures for oil and natural gas properties and a $63.6 million increase in proceeds mainly from our third-quarter 2015 divestiture of non-strategic and primarily non-operated properties. These changes were partially offset by a $25.4 million increase in investment in our equity method investee.
Our cash used in investing activities for the periods presented is summarized in the table below:
 
 
Nine months ended September 30,
(in thousands)
 
2015
 
2014
Capital expenditures:
 
 
 
 
Acquisition of oil and natural gas properties
 
$
—

 
$
(6,493
)
Acquisition of mineral interests
 
—

 
(7,305
)
Oil and natural gas properties
 
(490,351
)
 
(925,121
)
Midstream service assets
 
(35,237
)
 
(45,263
)
Other fixed assets
 
(8,539
)
 
(13,612
)
Investment in equity method investee
 
(63,011
)
 
(37,581
)
Proceeds from dispositions of capital assets, net of costs
 
65,261

 
1,627

Net cash used in investing activities
 
$
(531,877
)
 
$
(1,033,748
)
Capital expenditure budget
During the second quarter of 2015, our board of directors approved an increased capital expenditure budget of approximately $595.0 million for calendar year 2015, which includes capital requirements of our equity method investee but excludes acquisitions. During the third-quarter of 2015, our board of directors approved an additional $55.0 million of contributions to Medallion to be used for additional expansion projects. We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted.
The amount, timing and allocation of capital expenditures are largely discretionary and within management's control. If oil, NGL and natural gas prices decline below our acceptable levels, or costs increase above our acceptable levels, we may choose to defer a portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flow. Subject to financing alternatives, we may also increase our capital expenditures significantly to take advantage of opportunities we consider to be attractive. We consistently monitor and may adjust our projected capital expenditures in response to success or lack of success in drilling activities, changes in prices, availability of financing and joint venture opportunities, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, reduction of service costs, contractual obligations, internally generated cash flow and other factors both within and outside our control.

50


Cash flows provided by financing activities
Our net cash flows provided by financing activities were $353.5 million and $515.0 million for the nine months ended September 30, 2015 and 2014, respectively. For the nine months ended September 30, 2015, our primary sources of cash provided by financing activities were proceeds from our March 2015 Equity Offering, the issuance of our March 2023 Notes and borrowings on our Senior Secured Credit Facility, partially offset by the redemption of our January 2019 Notes and the payments on our Senior Secured Credit Facility during the quarter ended March 31, 2015. During the nine months ended September 30, 2014, our primary source of cash provided by financing activities was proceeds from the issuance of our January 2022 Notes.     
Our cash provided by financing activities for the periods presented is summarized in the table below:
 
 
Nine months ended September 30,
(in thousands)
 
2015
 
2014
Borrowings on Senior Secured Credit Facility
 
$
310,000

 
$
75,000

Payments on Senior Secured Credit Facility
 
(475,000
)
 
—

Issuance of March 2023 Notes
 
350,000

 
—

Issuance of January 2022 Notes
 
—

 
450,000

Redemption of January 2019 Notes
 
(576,200
)
 
—

Proceeds from issuance of common stock, net of offering costs
 
754,163

 
—

Purchase of treasury stock
 
(2,749
)
 
(4,075
)
Proceeds from exercise of employee stock options
 
—

 
1,885

Payments for debt issuance costs
 
(6,759
)
 
(7,791
)
Net cash provided by financing activities
 
$
353,455

 
$
515,019

Debt
As of September 30, 2015, 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, 2015, our Senior Secured Credit Facility, which matures November 4, 2018, had a maximum credit amount of $2.0 billion, a borrowing base of $1.25 billion, an aggregate elected commitment amount of $1.0 billion and $135.0 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 contains both financial and non-financial covenants. We were in compliance with these ratios as of September 30, 2015 and expect to be in compliance with them for the foreseeable future. See "Part II, Item 5. Other Information-Item 1.01 Entry into a material definitive agreement" below for additional information regarding the Fourth Amendment to the Senior Secured Credit Facility.
Senior unsecured notes. On March 18, 2015, we completed an offering of $350.0 million in aggregate principal amount of 6 1/4% senior unsecured notes due 2023. Our March 2023 Notes will mature on March 15, 2023 and bear an interest rate of 6 1/4% per annum and payable semi-annually in cash in arrears on March 15 and September 15 of each year, commencing September 15, 2015. Our March 2023 Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by LMS, GCM and certain of our future restricted subsidiaries. Our March 2023 Notes were issued under and are governed by an indenture and supplement thereto, each dated March 18, 2015 (collectively, the "2015 indenture"), among Laredo and Wells Fargo Bank, National Association, as trustee. The 2015 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 March 2023 Notes may be accelerated in certain circumstances upon an event of default as set forth in the 2015 indenture.

51


On January 23, 2014, we completed an offering of $450.0 million aggregate principal amount of 5 5/8% senior unsecured notes due 2022. Our 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. Our January 2022 Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by LMS, GCM and certain of our future restricted subsidiaries. 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. Our 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. Our May 2022 Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by LMS, GCM and certain of our future restricted subsidiaries. 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. Our January 2019 Notes were due to mature on February 15, 2019 and bore 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 January 2019 Notes were fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by LMS, GCM and certain of our future restricted subsidiaries. Our January 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 contained 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.
Utilizing proceeds from the March 2023 Notes and the March 2015 Equity Offering, we redeemed the January 2019 Notes in full on April 6, 2015. See Note 5.d to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for information regarding the early redemption of the January 2019 Notes.
Refer to Note 4 of our audited consolidated financial statements included in the 2014 Annual Report and Note 5 of our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of the March 2023 Notes, January 2022 Notes, May 2022 Notes, January 2019 Notes and our Senior Secured Credit Facility.
As of November 4, 2015, we had a total of $1.3 billion of senior unsecured notes outstanding and $135.0 million outstanding on the Senior Secured Credit Facility.
Obligations and commitments
As of September 30, 2015, our contractual obligations included our March 2023 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, 2014 to September 30, 2015, the material changes in our contractual obligations included (i) a decrease of $759.0 million in principal and interest due to the redemption of the January 2019 Notes, (ii) an increase of $525.0 million in principal and interest due to the March 2023 Notes offering, (iii) a decrease of $165.0 million outstanding on our Senior Secured Credit Facility, (iv) a decrease of $80.8 million on our interest obligations for our senior unsecured notes as semi-annual interest payments were made in January, February, May, July and September 2015, (iv) an increase of $16.0 million in our outstanding capital contribution commitment to our equity method investee due to new commitments to fund the construction of pipeline extensions to capture additional third-party production and (v) a decrease of $26.8 million for drilling contract commitments (on contracts other than those on a well-by-well basis).
Refer to Notes 2, 5, 6, 8, 9, 11, 14 and 15 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our contractual obligations.

52


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 net income or loss and other performance measures prepared in accordance with GAAP, such as operating income or loss or cash flow from operating activities. Adjusted EBITDA should not be considered in isolation or as a substitute for GAAP measures, such as net income or loss, operating income or loss or any other GAAP measure of liquidity or financial performance.
Adjusted EBITDA
Adjusted EBITDA is a non-GAAP financial measure that we define as net income or loss plus adjustments for income tax expense or benefit, depletion, depreciation and amortization, bad debt expense, impairment expense, non-cash stock-based compensation, restructuring expenses, 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, interest expense, write-off of debt issuance costs, gains or losses on disposal of assets, loss on early redemption of debt and buyout of minimum volume commitment. Adjusted EBITDA provides no information regarding a company’s capital structure, borrowings, interest costs, capital expenditures, working capital movement or tax position. Adjusted EBITDA does not represent funds available for discretionary use because those funds are required for debt service, capital expenditures and working capital, income taxes, franchise taxes and other commitments and obligations. However, our management believes Adjusted EBITDA is useful to an investor in evaluating our operating performance because this measure:
•
is widely used by investors in the oil and natural gas industry to measure a company’s operating performance without regard to items excluded from the calculation of such term, which can vary substantially from company to company depending upon accounting methods, book value of assets, capital structure and the method by which assets were acquired, among other factors;
•
helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure; and
•
 is used by our management for various purposes, including as a measure of operating performance, in presentations to our board of directors and as a basis for strategic planning and forecasting.
There are significant limitations to the use of Adjusted EBITDA as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss, the lack of comparability of results of operations to different companies and the different methods of calculating Adjusted EBITDA reported by different companies. Our measurements of Adjusted EBITDA for financial reporting as compared to compliance under our debt agreements differ.

53


The following presents a reconciliation of net income (loss) to Adjusted EBITDA:
 
 
Three months ended September 30,

Nine months ended September 30,
(in thousands)
 
2015

2014

2015

2014
Net income (loss)
 
$
(847,783
)

$
83,407


$
(1,245,289
)

$
64,295

Plus:
 






 


 

Deferred income tax expense (benefit)
 
41,258


45,778


(176,945
)

35,511

Depletion, depreciation and amortization
 
66,777


63,942


210,831


166,605

Bad debt expense

107


—


107


—

Impairment expense

906,850


—


1,397,327


—

Non-cash stock-based compensation, net of amounts capitalized
 
6,877


6,194


17,933


16,919

Restructuring expenses
 
—

 
—

 
6,042

 
—

(Gain) loss on derivatives, net

(142,580
)

(92,790
)

(141,836
)

1,447

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

66,142


4,531


175,879


(1,320
)
Cash settlements received for early terminations of commodity derivatives, net

—


—


—


76,660

Premiums paid for derivatives that matured during the period(1)
 
(1,248
)

(1,820
)

(3,918
)

(5,599
)
Interest expense
 
23,348


30,549


79,732


90,192

Write-off of debt issuance costs
 
—

 
—

 
—

 
124

Loss on disposal of assets, net

94


2,192


1,937


2,418

Loss on early redemption of debt
 
—

 
—

 
31,537

 
—

Buyout of minimum volume commitment
 
—

 
—

 
3,014

 
—

Adjusted EBITDA
 
$
119,842


$
141,983


$
356,351


$
447,252

______________________________________________________________________________
(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 unaudited consolidated financial statements.
In management’s opinion, the more significant reporting areas impacted by our judgments and estimates are (i) the choice of accounting method for oil and natural gas activities, (ii) estimation of oil 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 these 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, 2015. 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

54


2014 Annual Report. Additionally, see Note 2 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for a discussion of additional accounting policies and estimates made by management.
Recent accounting pronouncements
As of September 30, 2015, we early adopted new guidance regarding the presentation of debt issuance costs. For additional discussion of this early adoption and other recent accounting pronouncements, see Note 18 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.
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."

55


Item 3.    Quantitative and Qualitative Disclosures About Market Risk
The primary objective of the following is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term "market risk," in our case, refers to the risk of loss arising from adverse changes in oil, NGL and natural gas prices and in interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for hedging purposes, rather than for speculative trading.
Commodity price exposure
Due to the inherent volatility of oil, NGL 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 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 values of our commodity derivatives using an independent third-party valuation and recognize the associated gain or loss in our unaudited consolidated statements of operations.
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, 2015, 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
 
$
234,463

 
$
335,425

As of September 30, 2015 and December 31, 2014, the fair values of our open derivative contracts were $282.0 million and $312.3 million, respectively. Refer to Notes 2.e, 8 and 9 of our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional disclosures regarding our derivatives.

Interest rate risk
Our Senior Secured Credit Facility bears interest at a floating rate and, as of September 30, 2015, we had $135.0 million outstanding on our Senior Secured Credit Facility. Our January 2022 Notes, May 2022 Notes and March 2023 Notes bear fixed interest rates and we had $450.0 million, $500.0 million and $350.0 million outstanding, respectively, as of September 30, 2015, as shown in the table below. 
 
 
Expected maturity date
 
 
(in millions except for interest rates)
 
2015
 
2016
 
2017
 
2018
 
2019
 
Thereafter
 
Total
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
%
March 2023 Notes - fixed rate
 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
350.0

 
$
350.0

Average interest rate
 
—
%
 
—
%
 
—
%
 
—
%
 
—
%
 
6.250
%
 
6.250
%
Senior Secured Credit Facility - variable rate
 
$
—

 
$
—

 
$
—

 
$
135.0

 
$
—

 
$
—

 
$
135.0

Average interest rate
 
—
%
 
—
%
 
—
%
 
1.724
%
 
—
%
 
—
%
 
1.724
%
Counterparty and customer credit risk
As of September 30, 2015, our principal exposures to credit risk are through receivables of (i) $282.0 million from derivatives, (ii) $34.5 million from the sale of our oil, NGL and natural gas production, which we market to energy marketing companies and refineries, (iii) $25.6 million from joint interest parties, (iv) $21.7 million from matured derivatives and (v) $14.4 million from midstream product sales.
We are subject to credit risk due to the concentration of (i) our oil, NGL and natural gas receivables with several significant customers and (ii) our midstream service product sales receivable with one significant customer. On occasion we require our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.
We have entered into International Swap Dealers Association Master Agreements ("ISDA Agreements") with each of

56


our derivative counterparties, who also are 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 10 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional disclosures regarding credit risk.

57


Item 4.    Controls and Procedures
Evaluation of disclosure controls and procedures
As of the end of the period covered by this report, an evaluation of the effectiveness of the design and operation of Laredo's disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act), was performed under the supervision and with the participation of Laredo's management, including our principal executive officer and principal financial officer. Based on that evaluation, these officers concluded that Laredo's disclosure controls and procedures were effective as of September 30, 2015. 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, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

58


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 2014 Annual Report and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2015, as well as the updated risk factor set forth below. Other than such updates, there have been no material changes in our risk factors from those described in the 2014 Annual Report and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2015. The risks described in the 2014 Annual Report and our Quarterly Report on Form 10-Q for the quarter ended March 31, 2015 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.

Risks related to our business

As a result of the sustained commodity price decrease, we have taken and may be required to take further write-downs of the carrying values of our properties.

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on prevailing commodity prices and specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we have been required to and may be required to further write-down the carrying value of our properties. A write-down constitutes a non-cash charge to earnings.

Oil, NGL and natural gas prices have significantly declined since mid-2014 and have remained low in the third-quarter of 2015. Primarily as a result of these lower prices, our September 30, 2015 estimated proved reserves decreased 37 MMBOE from our December 31, 2014 reserves, converted to three streams. Additionally, we recorded non-cash full cost ceiling impairments of $488.0 million and $906.4 million in the second and third quarters of 2015, respectively. If prices remain at or below current levels, we will incur another impairment charge in the fourth quarter of 2015 and may incur further charges in the future. Such charges could have a material adverse effect on our results of operations for the periods in which they are taken. See Note 2.h to our audited consolidated financial statements included in our 2014 Annual Report for additional information.
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, 2015 - July 31, 2015
 
2,952

 
$
10.65

 
—

 
—

August 1, 2015 - August 31, 2015
 
4,419

 
$
8.70

 
—

 
—

September 1, 2015 - September 30, 2015
 
8,872

 
$
9.92

 
—

 
—

Total
 
16,243

 
 
 
 
 
 
______________________________________________________________________________
(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.


59


Item 4.    Mine Safety Disclosures

Not applicable.

Item 5.    Other Information

Disclosure pursuant to Section 13(r) of the Securities Exchange Act of 1934
Pursuant to Section 13(r) of the Exchange Act, we may be required to disclose in our annual and quarterly reports to the SEC, whether we or any of our "affiliates" knowingly engaged in certain activities, transactions or dealings relating to Iran or with certain individuals or entities targeted by 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, Santander Asset Management Investment Holdings Limited ("SAMIH"). SAMIH may therefore be deemed to be under common "control" with us; however, this statement is not meant to be an admission that common control exists.
The disclosure below relates solely to activities conducted by SAMIH and its 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 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.
We understand that SAMIH's affiliates intend to disclose in their next annual or quarterly SEC report that Santander UK plc ("Santander UK") holds frozen savings accounts and one current account for two customers resident in the U.K. who are currently designated by the U.S. for terrorism. The accounts held by each customer were blocked after the customer's designation and have remained blocked and dormant throughout the nine months ended September 30, 2015. Revenue generated on these accounts is negligible.
An Iranian national, resident in the U.K., who is currently designated by the U.S. under the Iranian Financial Sanctions Regulations and the Weapons of Mass Destruction Proliferators Sanctions Regulations ("NPWMD sanctions program"), holds a mortgage with Santander UK that was issued prior to any such designation. No further drawdown has been made (or would be allowed) under this mortgage although Santander UK continues to receive repayment installments. In the nine months ended September 30, 2015, total revenue in connection with the mortgage was approximately £2,928 while net profits were negligible relative to the overall profits of Santander UK. Santander UK does not intend to enter into any new relationships with this customer, and any disbursements will only be made in accordance with applicable sanctions. The same Iranian national also holds two investment accounts with Santander Asset Management UK Limited. The accounts have remained frozen during the nine months ended September 30, 2015. The investment returns are being automatically reinvested, and no disbursements have been made to the customer. Total revenue for the Santander Group in connection with the investment accounts was approximately £161 while net profits in the nine months ended September 30, 2015 were negligible relative to the overall profits of Banco Santander, S.A.
In addition, during the third-quarter of 2015, two additional Santander UK customers were designated. First, a U.K. national designated by the U.S. under the Specially Designated Global Terrorist ("SDGT") sanctions program who is on the U.S. Specially Designated National ("SDN") list. This customer holds a bank account which generated revenue of approximately £183 during the third quarter of 2015. A stop was placed on the account. Net profits in the third quarter of 2015 were negligible relative to the overall profits of Santander UK. Second, a U.K. national also designated by the U.S. under the SDGT sanctions program and on the U.S. SDN list, held a bank account. No transactions were made in the third quarter of 2015 and the account is blocked and in arrears.

Item 1.01 Entry into a material definitive agreement

On October 30, 2015, in connection with our regular semi-annual redetermination, we entered into the Fourth Amendment to Fourth Amended and Restated Credit Agreement among Laredo, Wells Fargo Bank, N.A., as administrative agent, the guarantors signatory thereto and the banks signatory thereto (the "Amendment"). Pursuant to the Amendment, among

60


other things, (i) the borrowing base was decreased from $1.25 billion to $1.15 billion, (ii) the amount of “permitted investments” in Medallion (regardless of whether made before, on or following the date of the Amendment) was increased to $225.0 million in the aggregate at any time and (iii) certain other terms of the Senior Secured Credit Facility, including certain non-financial representations and warranties and covenants, were amended as set forth in the Amendment. The Senior Secured Credit Facility matures on November 4, 2018 and has a maximum credit amount of $2.0 billion and an aggregate elected commitment of $1.0 billion. The foregoing summary of the Amendment is not complete and is qualified in its entirety by reference to the complete text of the Amendment, a copy of which is filed as Exhibit 10.1 to this Quarterly Report and is incorporated by reference into this Item 1.01.

Item 2.03 Creation of a direct financial obligation or an obligation under an off-balance sheet arrangement of a registrant
The disclosure set forth under Item 1.01 above is incorporated by reference into this Item 2.03.



61


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).
 
 
 
10.1*

 
Fourth Amendment to Fourth Amended and Restated Credit Agreement, dated as of October 30, 2015, among Laredo Petroleum, Inc., Wells Fargo Bank, N.A., as administrative agent, Laredo Midstream Services, LLC, Garden City Minerals, LLC and the banks signatory thereto.
 
 
 
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.



62


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 5, 2015
By:
/s/ Randy A. Foutch
 
 
Randy A. Foutch
 
 
Chairman and Chief Executive Officer
 
 
(principal executive officer)
 
 
 
Date: November 5, 2015
By:
/s/ Richard C. Buterbaugh
 
 
Richard C. Buterbaugh
 
 
Executive Vice President and Chief Financial Officer
 
 
(principal financial officer)
 
 
 
 
By:
 
Date: November 5, 2015
By:
/s/ Michael T. Beyer
 
 
Michael T. Beyer
 
 
Vice President - Controller and Chief Accounting Officer
 
 
(principal accounting officer)
 
 
 
 
 
 

63


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).
 
 
 
10.1*

 
Fourth Amendment to Fourth Amended and Restated Credit Agreement, dated as of October 30, 2015, among Laredo Petroleum, Inc., Wells Fargo Bank, N.A., as administrative agent, Laredo Midstream Services, LLC, Garden City Minerals, LLC and the banks signatory thereto.
 
 
 
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.



64