Laredo Petroleum, Inc. - FORM 10-Q - May 5, 2016

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EX-10.1 - EXHIBIT 10.1 - Laredo Petroleum, Inc.a1q1610-q101.htm
EX-31.2 - EXHIBIT 31.2 - Laredo Petroleum, Inc.a1q16ex312.htm
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EX-32.1 - EXHIBIT 32.1 - Laredo Petroleum, Inc.a1q16ex321.htm
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
 ý      QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the quarterly period ended March 31, 2016
 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 May 2, 2016: 213,406,700


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, and substantial decline in, oil, natural gas liquids ("NGL") and natural gas prices, which remain at low levels;
•
revisions to our reserve estimates as a result of changes in commodity prices and uncertainties;
•
impacts to our financial statements as a result of impairment write-downs;
•
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;
•
changes in domestic and global production, supply and demand for oil, NGL and natural gas;
•
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, especially during periods of sustained low commodity prices;
•
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;
•
our ability to generate sufficient cash to service our indebtedness, fund our capital requirements and generate future profits;
•
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 could result in widening price discounts to world crude prices and potential shut-in of production due to lack of sufficient markets;
•
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; and
•
our ability to recruit and retain the qualified personnel necessary to operate our business.

iii

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" and elsewhere in this Quarterly Report, under "Part I, Item 1A. Risk Factors" and "Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015 (the "2015 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)
 
 
March 31, 2016

December 31, 2015
Assets
 
 

 
 

Current assets:
 
 

 
 

Cash and cash equivalents
 
$
12,095

 
$
31,154

Accounts receivable, net
 
85,173

 
87,699

Derivatives
 
166,794

 
198,805

Other current assets
 
16,796

 
14,574

Total current assets
 
280,858

 
332,232

Property and equipment:
 
 
 
 

Oil and natural gas properties, full cost method:
 
 
 
 

Evaluated properties
 
5,216,178

 
5,103,635

Unevaluated properties not being depleted
 
116,905

 
140,299

   Less accumulated depletion and impairment
 
(4,417,833
)
 
(4,218,942
)
      Oil and natural gas properties, net
 
915,250

 
1,024,992

Midstream service assets, net
 
130,007

 
131,725

Other fixed assets, net
 
42,476

 
43,538

Property and equipment, net
 
1,087,733

 
1,200,255

Derivatives
 
63,414

 
77,443

Investment in equity method investee
 
194,822

 
192,524

Other assets, net
 
10,337

 
10,833

Total assets
 
$
1,637,164

 
$
1,813,287

Liabilities and stockholders' (deficit) equity
 
 
 
 

Current liabilities:
 
 
 
 

Accounts payable
 
$
23,382

 
$
14,181

Undistributed revenue and royalties
 
26,282

 
34,540

Accrued capital expenditures
 
43,657

 
61,872

Other current liabilities
 
62,753

 
106,222

Total current liabilities
 
156,074

 
216,815

Long-term debt, net
 
1,476,890

 
1,416,226

Derivatives
 
234

 
—

Asset retirement obligations
 
45,711

 
44,759

Other noncurrent liabilities
 
3,971

 
4,040

Total liabilities
 
1,682,880

 
1,681,840

Commitments and contingencies
 


 


Stockholders' (deficit) equity:
 
 
 
 
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued as of March 31, 2016 and December 31, 2015
 
—

 
—

Common stock, $0.01 par value, 450,000,000 shares authorized and 213,447,648 and 213,808,003 issued and outstanding as of March 31, 2016 and December 31, 2015, respectively
 
2,134

 
2,138

Additional paid-in capital
 
2,089,864

 
2,086,652

Accumulated deficit
 
(2,137,714
)
 
(1,957,343
)
Total stockholders' (deficit) equity
 
(45,716
)
 
131,447

Total liabilities and stockholders' (deficit) equity
 
$
1,637,164

 
$
1,813,287


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 March 31,
 
 
2016
 
2015
Revenues:






Oil, NGL and natural gas sales

$
73,142


$
118,118

Midstream service revenues

1,801


1,309

Sales of purchased oil
 
31,614

 
31,267

Total revenues

106,557


150,694

Costs and expenses:

 
 
 
Lease operating expenses

20,518


32,380

Production and ad valorem taxes
 
6,435

 
9,086

Midstream service expenses
 
609

 
1,574

Minimum volume commitments

—


1,656

Costs of purchased oil
 
32,946

 
31,200

General and administrative

19,451


21,855

Restructuring expenses
 
—

 
6,042

Accretion of asset retirement obligations

844


579

Depletion, depreciation and amortization

41,478


71,942

Impairment expense

161,064


878

Total costs and expenses

283,345


177,192

Operating loss

(176,788
)

(26,498
)
Non-operating income (expense):




 
Gain on derivatives, net

17,885


63,155

Income (loss) from equity method investee

2,298


(433
)
Interest expense

(23,705
)

(32,414
)
Interest and other income

99


123

Loss on disposal of assets, net

(160
)

(762
)
Non-operating income (expense), net

(3,583
)

29,669

Income (loss) before income taxes

(180,371
)

3,171

Income tax expense:






Deferred

—


(3,643
)
Total income tax expense

—


(3,643
)
Net loss

$
(180,371
)
 
$
(472
)
Net loss per common share:






Basic

$
(0.85
)

$
—

Diluted

$
(0.85
)
 
$
—

Weighted-average common shares outstanding:






Basic

211,560


162,426

Diluted

211,560


162,426

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

2


Laredo Petroleum, Inc.
Consolidated statement of stockholders' equity (deficit)
(in thousands)
(Unaudited) 
 
 
Common Stock
 
Additional
paid-in capital
 
Treasury Stock
(at cost)
 
Accumulated deficit
 
 
 
 
Shares
 
Amount
 
 
Shares
 
Amount
 
 
Total
Balance, December 31, 2015
 
213,808

 
$
2,138

 
$
2,086,652

 
—

 
$
—

 
$
(1,957,343
)
 
$
131,447

Restricted stock awards
 
24

 
—

 
—

 
—

 
—

 
—

 
—

Restricted stock forfeitures
 
(108
)
 
(1
)
 
1

 
—

 
—

 
—

 
—

Vested restricted stock exchanged for tax withholding
 
—

 
—

 
—

 
276

 
(1,412
)
 
—

 
(1,412
)
Retirement of treasury stock
 
(276
)
 
(3
)
 
(1,409
)
 
(276
)
 
1,412

 
—

 
—

Stock-based compensation
 
—

 
—

 
4,620

 
—

 
—

 
—

 
4,620

Net loss
 
—

 
—

 
—

 
—

 
—

 
(180,371
)
 
(180,371
)
Balance, March 31, 2016
 
213,448

 
$
2,134

 
$
2,089,864

 
—

 
$
—

 
$
(2,137,714
)
 
$
(45,716
)
 
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)
 
 
Three months ended March 31,
 
 
2016
 
2015
Cash flows from operating activities:

 


 

Net loss

$
(180,371
)

$
(472
)
Adjustments to reconcile net loss to net cash provided by operating activities:






Deferred income tax expense

—


3,643

Depletion, depreciation and amortization

41,478


71,942

Impairment expense

161,064


878

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

3,838


4,788

Mark-to-market on derivatives:






Gain on derivatives, net

(17,885
)

(63,155
)
Cash settlements received for matured derivatives, net

65,937


63,141

Cash settlements received for early terminations of derivatives, net

80,000


—

Change in net present value of deferred premiums paid for derivatives

72


43

Cash premiums paid for derivatives

(81,850
)

(1,421
)
Amortization of debt issuance costs

1,120


1,377

Cash settlement of performance unit awards
 
(6,394
)
 
(2,738
)
Other, net

(1,292
)

1,742

Decrease in accounts receivable
 
2,526

 
16,926

Increase in other assets
 
(2,186
)
 
(14,478
)
Increase (decrease) in accounts payable
 
9,201

 
(8,598
)
Decrease in undistributed revenues and royalties
 
(8,258
)
 
(19,222
)
Decrease in other accrued liabilities
 
(10,414
)
 
(28,714
)
(Decrease) increase in other noncurrent liabilities
 
(69
)
 
187

Increase in fair value of performance unit awards
 
—

 
996

Net cash provided by operating activities
 
56,517

 
26,865

Cash flows from investing activities:






Capital expenditures:






Oil and natural gas properties

(105,155
)

(243,733
)
Midstream service assets

(1,937
)

(20,434
)
Other fixed assets

(630
)

(3,919
)
Investment in equity method investee
 
(26,660
)
 
(14,495
)
Proceeds from dispositions of capital assets, net of costs

218


35

Net cash used in investing activities

(134,164
)

(282,546
)
Cash flows from financing activities:






Borrowings on Senior Secured Credit Facility

85,000


175,000

Payments on Senior Secured Credit Facility

(25,000
)

(475,000
)
Issuance of March 2023 Notes
 
—


350,000

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

 
754,163

Purchase of treasury stock

(1,412
)

(2,283
)
Payments for debt issuance costs

—


(6,427
)
Net cash provided by financing activities

58,588


795,453

Net (decrease) increase in cash and cash equivalents

(19,059
)

539,772

Cash and cash equivalents, beginning of period

31,154


29,321

Cash and cash equivalents, end of period

$
12,095


$
569,093

 
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, and the transportation of oil and natural gas from such 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" refers to Laredo, LMS and GCM 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 third parties with 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 and around Laredo's primary production corridors.
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, 2015 is derived from audited consolidated financial statements. In the opinion of management, the accompanying unaudited consolidated financial statements reflect all necessary adjustments to present fairly the Company's financial position as of March 31, 2016, results of operations for the three months ended March 31, 2016 and 2015 and cash flows for the three months ended March 31, 2016 and 2015.
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 2015 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 derivatives, deferred premiums and performance unit awards. As fair value is a market-based measurement, it is determined based on the assumptions that would be used by market participants. 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

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

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 2016 presentation. These reclassifications had no impact to previously reported net loss, stockholders' equity or cash flows.
d.    Accounts receivable
The Company sells produced and purchased 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.
Joint interest operations 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 some or all of 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 consisted of the following components for the periods presented:
(in thousands)
 
March 31, 2016
 
December 31, 2015
Oil, NGL and natural gas sales
 
$
31,060

 
$
25,582

Joint operations, net(1)
 
23,027

 
21,375

Matured derivatives
 
18,084

 
27,469

Sales of purchased oil and other products
 
12,324

 
11,775

Other
 
678

 
1,498

Total
 
$
85,173

 
$
87,699

______________________________________________________________________________
(1)
Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.2 million as of both March 31, 2016 and December 31, 2015.
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 puts, swaps, collars and, in prior periods, basis swaps.
Derivatives are recorded at fair value and are presented on a net basis 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 Note 9 for discussion regarding the fair value of the Company's derivatives. 
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 Notes 8 and 9 for discussion regarding the Company's derivatives.

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

f.    Property and equipment
The following table sets forth the Company's property and equipment as of the periods presented:
(in thousands)
 
March 31, 2016
 
December 31, 2015
Evaluated oil and natural gas properties
 
$
5,216,178

 
$
5,103,635

Less accumulated depletion and impairment
 
(4,417,833
)
 
(4,218,942
)
Evaluated oil and natural gas properties, net
 
798,345

 
884,693

 
 
 
 
 
Unevaluated properties not being depleted
 
116,905

 
140,299

 
 
 
 
 
Midstream service assets
 
148,112

 
147,811

Less accumulated depreciation
 
(18,105
)
 
(16,086
)
Midstream service assets, net
 
130,007

 
131,725

 
 
 
 
 
Depreciable other fixed assets
 
46,748

 
46,799

Less accumulated depreciation and amortization
 
(19,186
)
 
(18,169
)
Depreciable other fixed assets, net
 
27,562

 
28,630

 
 
 
 
 
Land
 
14,914

 
14,908

 
 
 
 
 
Total property and equipment, net
 
$
1,087,733

 
$
1,200,255

For the three months ended March 31, 2016 and 2015, depletion expense was $9.00 per barrel of oil equivalent ("BOE") sold and $16.08 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 depleted 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 depleted 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 revenues from proved oil and natural gas properties discounted at 10%. Per the SEC guidelines, 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 before differentials ("Benchmark Prices"). The Benchmark Prices are then adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead ("Realized Prices"). The Realized Prices are utilized to calculate the discounted future net revenues in the full cost ceiling calculation.

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

In the event the unamortized cost of evaluated oil and natural gas properties being depleted 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 following table presents the Benchmark Prices, Realized Prices and the corresponding non-cash full cost ceiling impairments recorded as of the periods presented:
 
 
For the quarters ended
 
 
March 31, 2016
 
December 31, 2015
 
September 30, 2015
 
June 30, 2015
 
March 31, 2015
Benchmark Prices
 
 
 
 
 
 
 
 
 
 
   Oil ($/Bbl)
 
$
42.77

 
$
46.79

 
$
55.73

 
$
68.17

 
$
79.21

   NGL ($/Bbl)
 
$
17.51

 
$
18.75

 
$
21.87

 
$
26.73

 
$
31.25

   Natural gas ($/MMBtu)
 
$
2.31

 
$
2.47

 
$
2.89

 
$
3.22

 
$
3.73

Realized Prices
 
 
 
 
 
 
 
 
 
 
   Oil ($/Bbl)
 
$
41.33

 
$
45.58

 
$
54.28

 
$
66.68

 
$
77.72

   NGL ($/Bbl)
 
$
11.25

 
$
12.50

 
$
15.25

 
$
19.56

 
$
23.75

   Natural gas ($/Mcf)
 
$
1.75

 
$
1.89

 
$
2.30

 
$
2.62

 
$
3.09

Non-cash full cost ceiling impairment (in thousands)
 
$
161,064

 
$
975,011

 
$
906,420

 
$
488,046

 
$
—

Full cost ceiling impairment expense is included in the "Impairment expense" line item in the unaudited consolidated statements of operations and in the financial information provided for the Company's exploration and production segment presented in Note 16.
g. Long-lived assets and inventory
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 inventory used in developing oil and natural gas properties and midstream service assets are carried at the lower of cost or market ("LCM") with cost determined using the weighted-average cost method 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 a replacement cost approach.
Beginning at March 31, 2016, frac pit water inventory used in developing oil and natural gas properties is carried at LCM with cost determined using the weighted-average cost method and is included in "Other current assets" on the unaudited consolidated balance sheets. The market price for frac pit water inventory is determined utilizing a replacement cost approach.
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. 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).

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

The following table presents inventory impairments recorded as of the periods presented:
 
 
Three months ended March 31,
(in thousands)
 
2016
 
2015
Inventory impairments:
 
 
 
 
Materials and supplies(1)
 
$
—

 
$
767

Line-fill(2)
 
—

 
111

Total inventory impairments
 
$
—

 
$
878

______________________________________________________________________________
(1)
Included in "Impairment expense" in the unaudited consolidated statements of operations and in "Impairment expense" for the Company's exploration and production segment presented in Note 16.
(2)
Included in "Impairment expense" in the unaudited consolidated statements of operations and in "Impairment expense" for the Company's midstream and marketing segment presented in Note 16.
h.    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 $6.4 million of debt issuance costs during the three months ended March 31, 2015 mainly as a result of the issuance of the March 2023 Notes (as defined below). No debt issuance costs were capitalized in the three months ended March 31, 2016. The Company had total debt issuance costs of $22.8 million and $23.9 million, net of accumulated amortization of $18.2 million and $17.0 million, as of March 31, 2016 and December 31, 2015, respectively.
No debt issuance costs were written off during the three months ended March 31, 2016 or 2015. Unamortized debt issuance costs related to the Company's senior unsecured notes are presented in "Long-term debt, net" on the Company's unaudited consolidated balance sheets. Unamortized debt issuance costs related to the Senior Secured Credit Facility are presented in "Other assets, net" on the Company's unaudited consolidated balance sheets. See Notes 5.a and 5.e for definitions of and information regarding the March 2023 Notes and the Senior Secured Credit Facility, respectively. See Note 5.g for additional discussion of debt issuance costs.
Future amortization expense of debt issuance costs as of the period presented is as follows:
(in thousands)
 
March 31, 2016
Remaining 2016

$
3,383

2017

4,575

2018

4,349

2019

2,915

2020

3,005

Thereafter

4,585

Total

$
22,812

i.    Other current assets and liabilities
Other current assets consist of the following components for the periods presented:
(in thousands)
 
March 31, 2016
 
December 31, 2015
Inventory(1)
 
$
8,538

 
$
6,974

Prepaid expenses and other
 
8,258

 
7,600

Total other current assets
 
$
16,796

 
$
14,574

______________________________________________________________________________
(1)
See Note 2.g for discussion of inventory held by the Company.

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

Other current liabilities consist of the following components for the periods presented:
(in thousands)
 
March 31, 2016
 
December 31, 2015
Accrued interest payable
 
$
21,663

 
$
24,208

Costs of purchased oil payable
 
12,423

 
12,189

Lease operating expense payable
 
11,624

 
13,205

Accrued compensation and benefits
 
5,492

 
14,342

Capital contribution payable to equity method investee(1)
 
923

 
27,583

Other accrued liabilities
 
10,628

 
14,695

Total other current liabilities
 
$
62,753

 
$
106,222

______________________________________________________________________________
(1)
See Notes 14, 15 and 19.b for additional discussion regarding our equity method investee.
j.    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 service 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, (iii) estimated removal and/or remediation costs for midstream service assets, (iv) estimated remaining life of midstream service 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)
 
Three months ended March 31, 2016
 
Year ended December 31, 2015
Liability at beginning of period
 
$
46,306

 
$
32,198

Liabilities added due to acquisitions, drilling, midstream service asset construction and other
 
107

 
2,236

Accretion expense
 
844

 
2,423

Liabilities settled upon plugging and abandonment
 
(194
)
 
(146
)
Liabilities removed due to sale of property
 
—

 
(2,005
)
Revision of estimates(1)
 
—

 
11,600

Liability at end of period
 
$
47,063

 
$
46,306

_____________________________________________________________________________
(1)
The revision of estimates that occurred during the year ended December 31, 2015 is mainly related to a change in the estimated remaining life per well due to the decline in commodity prices.

10
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 Note 9 for details regarding the fair value of the Company's derivatives.
l.    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.
m.    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, in prior periods, the 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.
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 March 31, 2016 or December 31, 2015.
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:
 
 
Three months ended March 31,
(in thousands)
 
2016
 
2015
Non-cash investing information:
 
 
 
 
Change in accrued capital expenditures
 
$
(18,215
)
 
$
(30,066
)
Change in accrued capital contribution to equity method investee(1)
 
$
(26,660
)
 
$
—

Capitalized asset retirement cost
 
$
107

 
$
515

Supplemental cash flow information:
 
 
 
 
Capitalized interest
 
$
39

 
$
98

______________________________________________________________________________
(1)
See Notes 14, 15 and 19.b for additional discussion regarding our equity method investee.
Note 3—2015 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 Laredo's common stock during the three months ended March 31, 2016.

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

Note 4—Divestiture
a. 2015 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 purchase price of $65.5 million. After transaction costs reflecting an economic effective date of July 1, 2015, the net proceeds were $64.8 million, net of working capital adjustments and post-closing 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.

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 period presented:
(in thousands)
 
Three months ended March 31, 2015
Oil, NGL and natural gas sales
 
$
2,078

Expenses(1)
 
2,612

_____________________________________________________________________________
(1)
Expenses include (i) lease operating expense, (ii) production and ad valorem tax expense, (iii) accretion expense and (iv) depletion expense.
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"). The March 2023 Notes 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. 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 the applicable indenture, designation of a subsidiary guarantor as a non-guarantor restricted subsidiary or as an unrestricted subsidiary in accordance with the applicable indenture, release from guarantee under the Senior Secured Credit Facility, or liquidation or dissolution (collectively, the "Releases").
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.

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

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"), utilizing a portion of the proceeds from the March 2015 Equity Offering and the March 2023 Notes offering, 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 March 31, 2016, 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 $1.15 billion and an aggregate elected commitment of $1.0 billion with $195.0 million outstanding and was subject to an interest rate of 1.94%. It contains both financial and non-financial covenants, all of which the Company was in compliance with as of March 31, 2016. Laredo is required to pay an annual commitment fee on the unused portion of the financial institutions' commitment of 0.375% to 0.5%, based on the ratio of outstanding revolving credit to the total commitment under the Senior Secured Credit Facility. Additionally, the Senior Secured Credit Facility provides for the issuance of letters of credit, limited to the lesser of total capacity or $20.0 million. No letters of credit were outstanding as of March 31, 2016 or 2015.
See Note 19.a for discussion of additional borrowings on, and changes to the borrowing base and aggregate elected commitment under, the Senior Secured Credit Facility subsequent to March 31, 2016.
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:
 
 
March 31, 2016
 
December 31, 2015
(in thousands)
 
Long-term
debt
 
Fair
value
 
Long-term
debt
 
Fair
value
January 2022 Notes
 
$
450,000

 
$
378,000

 
$
450,000

 
$
388,301

May 2022 Notes
 
500,000

 
432,500

 
500,000

 
460,000

March 2023 Notes
 
350,000

 
293,125

 
350,000

 
301,000

Senior Secured Credit Facility
 
195,000

 
194,946

 
135,000

 
134,993

Total value of debt
 
$
1,495,000

 
$
1,298,571

 
$
1,435,000

 
$
1,284,294

The fair values of the debt outstanding on the January 2022 Notes, May 2022 Notes and the March 2023 Notes were determined using the March 31, 2016 and December 31, 2015 quoted market price (Level 1) for each respective instrument. The fair values of the outstanding debt on the Senior Secured Credit Facility as of March 31, 2016 and December 31, 2015 were estimated utilizing pricing models for similar instruments (Level 2). See Note 9 for information about fair value hierarchy levels.

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

g.    Debt issuance costs
The following table summarizes the net presentation of the Company's long-term debt and debt issuance cost on the unaudited consolidated balance sheets for the periods presented:
 
 
March 31, 2016
 
December 31, 2015
(in thousands)
 
Long-term debt
 
Debt issuance costs, net
 
Long-term debt, net
 
Long-term debt
 
Debt issuance costs, net
 
Long-term debt, net
January 2022 Notes
 
$
450,000

 
$
(5,696
)
 
$
444,304

 
$
450,000

 
$
(5,939
)
 
$
444,061

May 2022 Notes
 
500,000

 
(6,847
)
 
493,153

 
500,000

 
(7,066
)
 
492,934

March 2023 Notes
 
350,000

 
(5,567
)
 
344,433

 
350,000

 
(5,769
)
 
344,231

Senior Secured Credit Facility(1)
 
195,000

 
—

 
195,000

 
135,000

 
—

 
135,000

Total
 
$
1,495,000

 
$
(18,110
)
 
$
1,476,890

 
$
1,435,000

 
$
(18,774
)
 
$
1,416,226

______________________________________________________________________________
(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. On March 30, 2016, the Company's compensation committee recommended, and the Company's board of directors adopted, subject to stockholder approval, an amendment to the LTIP to, among other things, increase the number of shares of common stock available for issuance under the LTIP by 14,350,000 shares (the "Amendment"), enabling the continued use of the LTIP for share-based awards. The Company is seeking stockholder approval of the Amendment in connection with its 2016 Annual Meeting of Stockholders on May 25, 2016.
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 accounted for as equity instruments, and in prior periods, its performance unit awards were 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) 33%, 33% and 34% per year beginning on the first anniversary date of the grant, (ii) 50% in year two and 50% in year three, (iii) fully on the first anniversary of the grant date and (iv) 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.
    

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

The following table reflects the outstanding restricted stock awards for the three months ended March 31, 2016:
(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, 2015
 
2,539

 
$
15.26

Granted
 
24

 
$
5.45

Forfeited
 
(108
)
 
$
16.69

Vested(1)
 
(981
)
 
$
16.24

Outstanding as of March 31, 2016
 
1,474

 
$
14.34

______________________________________________________________________________
(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 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 March 31, 2016, unrecognized stock-based compensation related to the restricted stock awards expected to vest was $16.6 million. Such cost is expected to be recognized over a weighted-average period of 1.60 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 three months ended March 31, 2016:
(in thousands, except for weighted-average price and contractual term)
 
Restricted
stock option
awards
 
Weighted-average
 price
(per option)
 
Weighted-average
remaining contractual term
(years)
Outstanding as of December 31, 2015
 
1,778

 
$
17.86

 
7.91
Granted
 
—

 
$
—

 

Exercised
 
—

 
$
—

 

Expired or canceled
 
(2
)
 
$
20.94

 

Forfeited
 
(126
)
 
$
16.07

 

Outstanding as of March 31, 2016
 
1,650

 
$
18.00

 
7.46
Vested and exercisable at end of period(1)
 
955

 
$
19.55

 
6.86
Expected to vest at end of period(2)
 
685

 
$
15.76

 
8.31
_____________________________________________________________________________
(1)
The vested and exercisable options as of March 31, 2016 had no aggregate intrinsic value.
(2)
The restricted stock options expected to vest as of March 31, 2016 had no aggregate intrinsic value.
The Company utilizes the Black-Scholes option pricing model to determine the fair value of restricted stock option awards and recognizes 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 March 31, 2016, unrecognized stock-based compensation related to restricted stock option awards expected to vest was $5.4 million. Such cost is expected to be recognized over a weighted-average period of 2.14 years.
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.

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

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 520,896 outstanding 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. The 232,118 outstanding 2014 Performance Share Awards have a performance period of January 1, 2014 to December 31, 2016, and any shares earned under such awards are expected to be issued in the first quarter of 2017 if the performance criteria are met.
    
    
The following table reflects the performance share award activity for the three months ended March 31, 2016:
(in thousands, except for weighted-average grant date fair values)
 
Performance share awards
 
Weighted-average
grant date
fair value (per award)
Outstanding as of December 31, 2015
 
874

 
$
20.06

Granted
 
—

 
$
—

Forfeited
 
(121
)
 
$
20.25

Vested
 
—

 
$
—

Outstanding as of March 31, 2016
 
753

 
$
20.03

As of March 31, 2016, unrecognized stock-based compensation related to the 2015 Performance Share Awards and the 2014 Performance Share Awards was $7.3 million. Such cost is expected to be recognized over a weighted-average period of 1.63 years.
d.    Stock-based compensation award expense
The following has been recorded to stock-based compensation expense for the periods presented:
 
 
Three months ended March 31,
(in thousands)
 
2016

2015
Restricted stock award compensation, net of amounts capitalized
 
$
3,192

 
$
3,280

Restricted stock option award compensation, net of amounts capitalized
 
525

 
673

Restricted performance share award compensation, net of amounts capitalized
 
121

 
835

Total stock-based compensation, net of amounts capitalized
 
$
3,838

 
$
4,788

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") were subject to a combination of market and service vesting criteria. These awards were accounted for as liability awards as they were settled in cash at the end of the requisite service period based on the achievement of certain performance criteria.
The 44,481 settled 2013 Performance Unit Awards had a performance period of January 1, 2013 to December 31, 2015 and, as their performance criteria were satisfied, they were paid at $143.75 per unit during the first quarter of 2016. 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 $100.00 per unit during the first quarter of 2015.
For the three months ended March 31, 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 as of December 31, 2015, the corresponding liability is included in "Other current liabilities" on the unaudited consolidated balance sheets. Due to

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

the quarterly re-measurement of the fair value of the 2013 Performance Unit Awards as of March 31, 2015, compensation expense for the three months ended March 31, 2015 was $1.0 million.
f.    2016 contingent awards
On February 19, 2016, following the filing of the 2015 Annual Report, the Company's compensation committee approved contingent awards to employees for 2016. These contingent awards consist of restricted stock awards, stock option awards and performance share awards (payable in the Company's common stock), in the aggregate amounts identified in the schedule set forth below. All of these contingent awards are conditional and subject to stockholder approval of the Amendment. If such stockholder approval is not obtained, the following contingent awards will be canceled:
Contingent award type
 
Number of awards
Restricted stock(1)
 
2,771,474

Stock options(2)
 
994,022

Performance shares(3)
 
1,790,067

     Total
 
5,555,563

______________________________________________________________________________
(1)
If stockholder approval of the Amendment is obtained, these restricted stock awards granted in 2016 will vest 33%, 33% and 34% per year beginning on February 19, 2017.
(2)
If stockholder approval of the Amendment is obtained, these stock option awards will (i) have an exercise price of $4.10 per share, (ii) have an expiration date of February 19, 2026 and (iii) vest and become exercisable on a time basis in four equal installments on each of the first four anniversaries beginning February 19, 2017.
(3)
If stockholder approval of the Amendment is obtained, these performance share awards will have a performance period of January 1, 2016 to December 31, 2018 and will be paid in the Company's common stock in the first quarter of 2019 if the performance criteria are met.
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.
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 has no unrecognized tax benefits related to uncertain tax positions in the unaudited consolidated financial statements as of March 31, 2016 or December 31, 2015.
The Company is subject to federal and state income taxes and the Texas franchise tax. Income tax expense for the periods presented consisted of the following:
 
 
Three months ended March 31,
(in thousands)

2016
 
2015
Current taxes

$
—

 
$
—

Deferred taxes

—

 
(3,643
)
Income tax expense

$
—

 
$
(3,643
)

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

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

Three months ended March 31,
(in thousands)

2016
 
2015
Income tax benefit (expense) computed by applying the statutory rate

$
63,130

 
$
(1,110
)
State income tax and change in valuation allowance

728

 
91

Non-deductible stock-based compensation

—

 
(91
)
Stock-based compensation tax deficiency

(3,822
)
 
(2,457
)
Increase in deferred tax valuation allowance

(59,895
)
 
(5
)
Other items

(141
)
 
(71
)
Income tax expense

$
—

 
$
(3,643
)
 
For the three months ended March 31, 2016, the effective tax rate on loss before income taxes was not meaningful due to the valuation allowance recorded. For the three months ended March 31, 2015, the effective tax rate on income before income taxes was not meaningful due to the significant effect of discrete items on a relatively small amount of income. The Company's effective tax rate is affected by changes in valuation allowances, recurring permanent differences and by discrete items that may occur in any given year, but are not consistent from year to year.
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. During the year ended December 31, 2015 and the three months ended March 31, 2016, in evaluating whether it was more likely than not that the Company's net deferred tax assets were realized through future net income, management considered all available positive and negative evidence, including (i) its earnings history, (ii) its ability to recover net operating loss carry-forwards, (iii) the existence of significant proved oil and natural gas reserves, (iv) its ability to use tax planning strategies, (v) its current price protection utilizing oil and natural gas hedges, (vi) its future revenue and operating cost projections and (vii) the current market prices for oil and natural gas. Based on all the evidence available, during the year ended December 31, 2015, management determined it was more likely than not that the net deferred tax assets were not realizable, and therefore recorded a valuation allowance of $676.0 million. During the three months ended March 31, 2016, an additional valuation allowance of $57.7 million was recorded.
The impact of significant discrete items is separately recognized in the quarter in which the discrete items 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 grant date. The exercise of stock option awards could result in federal and state income tax expense or benefits related to the difference between the fair value of the stock option at the 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 months ended March 31, 2016 and 2015, certain shares related to restricted stock awards vested at times when the Company's stock price was lower than the fair value of those shares at the time of the grant. As a result, the income tax deduction related to such shares is less than the expense previously recognized for book purposes. During the three months ended March 31, 2016 and 2015, no restricted stock options were exercised. 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 March 31,
(in thousands)
 
2016
 
2015
Vesting of restricted stock
 
$
(3,875
)
 
$
(2,501
)
Exercise of restricted stock options
 
—

 
—

Tax expense due to shortfalls
 
$
(3,875
)
 
$
(2,501
)

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

Significant components of the Company's net deferred tax asset for the periods presented are as follows:
(in thousands)
 
March 31, 2016
 
December 31, 2015
Oil and natural gas properties, midstream service assets and other fixed assets
 
$
324,601

 
$
306,997

Net operating loss carry-forward
 
507,227

 
479,022

Derivatives
 
(82,908
)
 
(98,675
)
Stock-based compensation
 
7,530

 
11,597

Equity method investee
 
(27,728
)
 
(31,711
)
Accrued bonus
 
1,337

 
4,763

Capitalized interest
 
2,359

 
2,525

Other
 
2,593

 
2,820

Net deferred tax asset before valuation allowance
 
735,011

 
677,338

Valuation allowance
 
(735,011
)
 
(677,338
)
Net deferred tax asset
 
$
—

 
$
—

The Company had federal net operating loss carry-forwards totaling $1.4 billion and state of Oklahoma net operating loss carry-forwards totaling $40.9 million as of March 31, 2016. These carry-forwards begin expiring in 2026. Additionally, these carry-forwards include windfall tax deductions from vestings of certain restricted stock awards and stock option exercises that were not recorded in the Company's income tax provision. The amount of windfall tax benefit recognized in additional paid-in capital is limited to the amount of benefit realized currently in income taxes payable. As of March 31, 2016, 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's income tax returns for the years 2012 through 2015 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 or had operations. Additionally, the statute of limitations for examination of federal net operating loss carry-forwards typically does not begin to run until the year the attribute is utilized in a tax return.
Note 8—Derivatives
a. Derivatives
The Company engages in derivative transactions such as puts, swaps, collars and, in prior periods, basis swaps to hedge price risks due to unfavorable changes in oil and natural gas prices related to its production. As of March 31, 2016, the Company had 21 open derivative contracts with financial institutions that extend from April 2016 to December 2018. None of these contracts were designated as hedges for accounting purposes. The contracts are recorded at fair value on the unaudited consolidated balance sheets and gains and losses are recognized in current period earnings. Gains and losses on derivatives are reported on the unaudited consolidated statements of operations on the "Gain on derivatives, net" line item.
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.
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 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.
In the prior year, the oil basis swap transactions had an established fixed basis differential. The Company's oil basis swaps' differential was between the West Texas Intermediate-Argus Americas Crude (Midland) ("WTI Midland") index crude

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

oil price and the West Texas Intermediate NYMEX ("WTI NYMEX") index crude oil price. When the WTI NYMEX price less the fixed basis differential was greater than the actual WTI Midland price, the difference multiplied by the hedged contract volume was paid to the Company by the counterparty. When the WTI NYMEX price less the fixed basis differential was less than the actual WTI Midland price, the difference multiplied by the hedged contract volume was paid by the Company to the counterparty.

During the three months ended March 31, 2016, the Company successfully completed a hedge restructuring by early terminating the floors of certain derivative contract collars that resulted in a termination amount of $80 million, which was settled in full by applying the proceeds to prepay the premiums on two new derivatives entered into during the restructuring.

During the three months ended March 31, 2016, the following derivatives were terminated:
 
 
Aggregate volumes
 
Floor price
 
Contract period
Oil (volumes in Bbl):
 
 

 
 
 
 
Put portion of the associated collars
 
2,263,000

 
$
80.00

 
January 2017 - December 2017
    
During the three months ended March 31, 2016, the following derivatives were entered into:
 
 
Aggregate volumes
 
Floor price
 
Contract period
Oil (volumes in Bbl):
 
 

 
 
 
 
Put(1)
 
2,263,000

 
$
60.00

 
January 2017 - December 2017
Put(2)
 
2,098,750

 
$
60.00

 
January 2017 - December 2018
Natural gas (volumes in MMBtu):(3)
 
 
 
 
 
 
Put
 
8,040,000

 
$
2.50

 
January 2017 - December 2017
Put
 
8,220,000

 
$
2.50

 
January 2018 - December 2018
_____________________________________________________________________________
(1)
As part of the Company's hedge restructuring, this put replaced the early terminated put portion of the restructured derivative contract collars. A premium of $40.0 million was paid at contract inception.
(2)
As part of the Company's hedge restructuring, a premium of $40.0 million was paid at contract inception.
(3)
There are $4.3 million in deferred premiums associated with these contracts.

The following represents cash settlements received for derivatives, net for the periods presented:
 
 
Three months ended March 31,
(in thousands)
 
2016
 
2015
Cash settlements received for matured derivatives, net
 
$
65,937

 
$
63,141

Cash settlements received for early terminations of derivatives, net(1)
 
80,000

 
—

Cash settlements received for derivatives, net
 
$
145,937

 
$
63,141

_____________________________________________________________________________
(1)
The settlements amount for the three months ended March 31, 2016 includes $4.0 million in deferred premiums which were settled net with the early terminated contracts from which they derive.
    
    

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

The following table summarizes open positions as of March 31, 2016, and represents, as of such date, derivatives in place through December 2018 on annual production volumes:
 
 
Remaining Year
2016
 
Year
2017
 
Year
2018
Oil positions:(1)
 
 

 
 
 
 

Puts:
 
 

 
 

 
 

Hedged volume (Bbl)
 
972,000

 
1,049,375

 
1,049,375

Weighted-average price ($/Bbl)
 
$
45.00

 
$
60.00

 
$
60.00

Swaps:
 
 

 
 

 
 

Hedged volume (Bbl)
 
1,182,500

 
—

 
—

Weighted-average price ($/Bbl)
 
$
84.82

 
$
—

 
$
—

Collars:
 
 

 
 

 
 

Hedged volume (Bbl)
 
2,743,750

 
2,628,000

 
—

Weighted-average floor price ($/Bbl)
 
$
73.99

 
$
60.00

 
$
—

Weighted-average ceiling price ($/Bbl)
 
$
89.63

 
$
97.22

 
$
—

Totals:
 
 
 
 
 
 
Total volume hedged with floor price (Bbl)
 
4,898,250

 
3,677,375

 
1,049,375

Weighted-average floor price ($/Bbl)
 
$
70.85

 
$
60.00

 
$
60.00

Total volume hedged with ceiling price (Bbl)
 
3,926,250

 
2,628,000

 
—

Weighted-average ceiling price ($/Bbl)
 
$
88.18

 
$
97.22

 
$
—

Natural gas positions:(2)
 
 

 
 

 
 

Puts:
 
 
 
 
 
 
Hedged volume (MMBtu)
 
—

 
8,040,000

 
8,220,000

Weighted-average price ($/MMBtu)
 
$
—

 
$
2.50

 
$
2.50

Collars:
 
 

 
 

 
 

Hedged volume (MMBtu)
 
14,025,000

 
5,475,000

 
—

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

 
$
3.00

 
$
—

Weighted-average ceiling price ($/MMBtu)
 
$
5.60

 
$
4.00

 
$
—

Totals:
 
 
 
 
 
 
Total volume hedged with floor price (MMBtu)
 
14,025,000

 
13,515,000

 
8,220,000

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

 
$
2.70

 
$
2.50

Total volume hedged with ceiling price (MMBtu)
 
14,025,000

 
5,475,000

 
—

Weighted-average ceiling price ($/MMBtu)
 
$
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 WTI NYMEX Light Sweet Crude Oil Futures Contract for each NYMEX Trading Day during each month.
(2)
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 derivatives are subject to counterparty netting under agreements governing such derivatives. The Company's oil and natural gas derivatives are presented on a net 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

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

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 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 months ended March 31, 2016 or 2015.

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 as of the periods presented:
(in thousands)
 
Level 1
 
Level 2
 
Level 3
 
Total gross fair value
 
Amounts offset
 
Net fair value presented on the unaudited consolidated balance sheets
As of March 31, 2016:
 
 
 
 
 
 
 
 
 
 
 
 
Assets
 
 
 
 
 
 
 
 
 
 
 
 
Current:
 
 
 
 
 
 
 
 
 
 
 
 
Oil derivatives
 
$
—

 
$
160,789

 
$
—

 
$
160,789

 
$
—

 
$
160,789

Natural gas derivatives
 
—

 
14,401

 
—

 
14,401

 
—

 
14,401

Oil deferred premiums
 
—

 
—

 
—

 
—

 
(7,736
)
 
(7,736
)
Natural gas deferred premiums
 
—

 
—

 
—

 
—

 
(660
)
 
(660
)
Noncurrent:
 
 
 
 
 
 
 
 
 
 
 
 
Oil derivatives
 
$
—

 
$
62,443

 
$
—

 
$
62,443

 
$
—

 
$
62,443

Natural gas derivatives
 
—

 
5,395

 
—

 
5,395

 
(3,345
)
 
2,050

Oil deferred premiums
 
—

 
—

 
—

 
—

 
(747
)
 
(747
)
Natural gas deferred premiums
 
—

 
—

 
—

 
—

 
(332
)
 
(332
)
Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
Current:
 
 
 
 
 
 
 
 
 
 
 
 
Oil derivatives
 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

Natural gas derivatives
 
—

 
—

 
—

 
—

 
—

 
—

Oil deferred premiums
 
—

 
—

 
(7,736
)
 
(7,736
)
 
7,736

 
—

Natural gas deferred premiums
 
—

 
—

 
(660
)
 
(660
)
 
660

 
—

Noncurrent:
 
 
 
 
 
 
 
 
 
 
 
 
Oil derivatives
 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

Natural gas derivatives
 
—

 
—

 
—

 
—

 
3,345

 
3,345

Oil deferred premiums
 
—

 
—

 
(747
)
 
(747
)
 
747

 
—

Natural gas deferred premiums
 
—

 
—

 
(3,911
)
 
(3,911
)
 
332

 
(3,579
)
Net derivative position
 
$
—

 
$
243,028

 
$
(13,054
)
 
$
229,974

 
$
—

 
$
229,974


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 unaudited consolidated balance sheets
As of December 31, 2015:
 
 
 
 
 
 
 
 
 
 
 
 
Assets
 
 
 
 
 
 
 
 
 
 
 
 
Current:
 
 
 
 
 
 
 
 
 
 
 
 
Oil derivatives
 
$
—

 
$
194,940

 
$
—

 
$
194,940

 
$
—

 
$
194,940

Natural gas derivatives
 
—

 
13,166

 
—

 
13,166

 
—

 
13,166

Oil deferred premiums
 
—

 
—

 
—

 
—

 
(9,301
)
 
(9,301
)
Natural gas deferred premiums
 
—

 
—

 
—

 
—

 
—

 
—

Noncurrent:
 
 
 
 
 
 
 
 
 
 
 
 
Oil derivatives
 
$
—

 
$
80,302

 
$
—

 
$
80,302

 
$
—

 
$
80,302

Natural gas derivatives
 
—

 
2,459

 
—

 
2,459

 
—

 
2,459

Oil deferred premiums
 
—

 
—

 
—

 
—

 
(4,877
)
 
(4,877
)
Natural gas deferred premiums
 
—

 
—

 
—

 
—

 
(441
)
 
(441
)
Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
Current:
 
 
 
 
 
 
 
 
 
 
 
 
Oil derivatives
 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

Natural gas derivatives
 
—

 
—

 
—

 
—

 
—

 
—

Oil deferred premiums
 
—

 
—

 
(9,301
)
 
(9,301
)
 
9,301

 
—

Natural gas deferred premiums
 
—

 
—

 
—

 
—

 
—

 
—

Noncurrent:
 
 
 
 
 
 
 
 
 
 
 
 
Oil derivatives
 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

Natural gas derivatives
 
—

 
—

 
—

 
—

 
—

 
—

Oil deferred premiums
 
—

 
—

 
(4,877
)
 
(4,877
)
 
4,877

 
—

Natural gas deferred premiums
 
—

 
—

 
(441
)
 
(441
)
 
441

 
—

Net derivative position
 
$
—

 
$
290,867

 
$
(14,619
)
 
$
276,248

 
$
—

 
$
276,248

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 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 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 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 for the calendar years presented:
(in thousands)
 
March 31, 2016
Remaining 2016
 
$
6,779

2017
 
4,397

2018
 
2,100

  Total
 
$
13,276

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

Three months ended March 31,
(in thousands)

2016
 
2015
Balance of Level 3 at beginning of period

$
(14,619
)
 
$
(9,285
)
Change in net present value of deferred premiums for derivatives

(72
)
 
(43
)
Total purchases and settlements:

 
 
 
Purchases

(4,112
)
 
(975
)
Settlements(1)

5,749

 
1,421

Balance of Level 3 at end of period

$
(13,054
)
 
$
(8,882
)
_____________________________________________________________________________
(1)
The amount for the three months ended March 31, 2016 includes $3.9 million which represents the present value of deferred premiums settled in the Company's restructuring upon their early termination.
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.g for discussion regarding the Company's impairments of materials and supplies and line-fill for the three months ended March 31, 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 prices used in the calculation of discounted cash flows and the Company's first-quarter 2016 full cost ceiling impairment.
Note 10—Net loss per share
Basic net loss per share is computed by dividing net loss by the weighted-average number of common shares outstanding for the period. Diluted net loss per share reflects the potential dilution of non-vested restricted stock awards, performance share awards and outstanding restricted stock options. For the three months ended March 31, 2016 and 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 loss per share.
The following is the calculation of basic and diluted weighted-average common shares outstanding and net loss per share for the periods presented:
 
 
Three months ended March 31,
(in thousands, except for per share data)
 
2016
 
2015
Net loss (numerator):
 
 
 
 
Net loss—basic and diluted
 
$
(180,371
)
 
$
(472
)
Weighted-average common shares outstanding (denominator):
 
 
 
 
Basic
 
211,560


162,426

Diluted
 
211,560


162,426

Net loss per share:
 
 
 
 
Basic
 
$
(0.85
)
 
$
—

Diluted
 
$
(0.85
)
 
$
—


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

Note 11—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. The Company's sales of purchased oil are made to one customer. 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 12—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.

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 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. Future commitments of $3.5 million as of March 31, 2016 are not recorded in the accompanying unaudited consolidated balance sheets. Management does not currently anticipate the early termination of any existing contracts in 2016 that would result in a substantial penalty.

c.    Firm sale and transportation commitments
The Company has committed to deliver for sale or transportation fixed volumes of product under certain contractual arrangements that specify the delivery of a fixed and determinable quantity. If not fulfilled, the Company is subject to minimal volume penalties. These commitments are normal and customary for the Company's business. Future commitments of $411.8 million as of March 31, 2016 are not recorded in the accompanying unaudited consolidated balance sheets. The Company's production has been equivalent or greater than its delivery commitments during the most recent year, and management expects such production will continue to exceed the Company's future commitments. However, in certain instances, the Company has used spot market purchases to meet its commitments in certain locations or due to favorable pricing. Management anticipates continuing this practice in the future. Also, if production is not sufficient to satisfy the Company's delivery commitments, the Company can and may use spot market purchases to fulfill the commitments.
 
d.    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.
 

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

e.    Other commitments

See Notes 2.i, 15.a and 19.b for the amount of and discussion regarding the commitments to the Company's non-consolidated variable interest entity ("VIE").
Note 13—2015 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 from 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 three months ended March 31, 2015 related to the RIF. There were no comparative amounts recorded in the three months ended March 31, 2016.
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 $26.7 million and $14.5 million during the three months ended March 31, 2016 and 2015, 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.b for discussion regarding a contribution made to Medallion subsequent to March 31, 2016. All LMS cash contributions made during the three months ended March 31, 2016 were for commitments that were fully accrued for in the Company's audited consolidated financial statements at December 31, 2015.
LMS holds 49% of Medallion's 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."
During the three months ended March 31, 2016, Medallion continued expansion activities on existing portions of its pipeline infrastructure in order to gather and transport additional third-party oil production. See Note 15.a for discussion of items included in the Company's unaudited consolidated financial statements related to Medallion.

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

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 March 31,
(in thousands)
 
2016
 
2015
Midstream service revenues
 
$
—

 
$
97

Minimum volume commitments
 
—

 
1,656

Interest and other income
 
—

 
108

The following table summarizes items included in the unaudited consolidated balance sheets related to Medallion as of the dates presented:
(in thousands)
 
March 31, 2016
 
December 31, 2015
Accounts receivable, net
 
$
—

 
$
1,163

Other assets, net(1)
 
1,025

 
1,025

Other current liabilities(2)
 
923

 
27,583

______________________________________________________________________________
(1)
Amounts included in "Other assets, net" above represent LMS owned line-fill in Medallion's pipeline.
(2)
Amounts included in "Other current liabilities" above represent LMS' capital contribution payable to Medallion. See Note 14 for additional discussion of Medallion and Note 19.b 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 was on the board of directors of Targa until May 18, 2015.
The following table summarizes the oil, NGL and natural gas sales and midstream service revenues received from Targa included in the unaudited consolidated statements of operations for the periods presented:
 
 
Three months ended March 31,
(in thousands)
 
2016

2015
Oil, NGL and natural gas sales
 
$
17,805

 
$
19,631

Midstream service revenues
 
135

 
—

The following table summarizes the amounts included in accounts receivable, net from Targa in the unaudited consolidated balance sheets as of the dates presented:
(in thousands)
 
March 31, 2016

December 31, 2015
Accounts receivable, net
 
$
7,877

 
$
6,097

c.    Archrock Partners, L.P.
The Company has a compression arrangement with affiliates of Archrock Partners, L.P., formerly Exterran Partners L.P. ("Archrock"). One of Laredo's directors is on the board of directors of Archrock GP LLC, an affiliate of Archrock.
The following table summarizes the lease operating expenses related to Archrock included in the unaudited consolidated statements of operations for the periods presented:
 
 
Three months ended March 31,
(in thousands)
 
2016

2015
Lease operating expenses
 
$
475

 
$
385


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

The following table summarizes the capital expenditures related to Archrock included in the unaudited consolidated statements of cash flows for the periods presented:
 
 
Three months ended March 31,
(in thousands)
 
2016

2015
Capital expenditures:
 
 
 
 
Midstream service assets
 
$
20

 
$
46

The following table summarizes the amounts included in accounts payable from Archrock in the unaudited consolidated balance sheets as of the dates presented:
(in thousands)
 
March 31, 2016
 
December 31, 2015
Accounts payable
 
$
18

 
$
13

d.    Helmerich & Payne, Inc.
The Company has had drilling contracts with Helmerich & Payne, Inc. ("H&P"). Laredo's Chairman and Chief Executive Officer is on the board of directors of H&P.
The following table summarizes the capitalized oil and natural gas properties related to H&P included in the unaudited consolidated statements of cash flows for the periods presented:
 
 
Three months ended March 31,
(in thousands)
 
2016
 
2015
Capital expenditures:
 
 
 
 
Oil and natural gas properties
 
$
—

 
$
2,257

Note 16—Segments
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 third parties with 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 and around Laredo's primary production corridors.

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

The following table presents selected financial information, for the periods presented, regarding the Company's operating segments on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis:
(in thousands)
 
Exploration and production
 
Midstream and marketing
 
Eliminations
 
Consolidated company
Three months ended March 31, 2016:
 
 
 
 
 
 
 
 
Oil, NGL and natural gas sales
 
$
73,142

 
$
—

 
$
—

 
$
73,142

Midstream service revenues
 
—

 
11,267

 
(9,466
)
 
1,801

Sales of purchased oil
 
—

 
31,614

 
—

 
31,614

Total revenues
 
73,142

 
42,881

 
(9,466
)
 
106,557

Lease operating expense, including production tax
 
29,364

 
—

 
(2,411
)
 
26,953

Midstream service expenses
 
—

 
6,509

 
(5,900
)
 
609

Costs of purchased oil
 
—

 
32,946

 
—

 
32,946

General and administrative(1)
 
17,679

 
1,772

 
—

 
19,451

Depletion, depreciation and amortization(2)
 
39,292

 
2,186

 
—

 
41,478

Impairment expense
 
161,064

 
—

 
—

 
161,064

Other operating costs and expenses(3)
 
792

 
52

 
—

 
844

Operating loss
 
$
(175,049
)
 
$
(584
)
 
$
(1,155
)
 
$
(176,788
)
Other financial information:
 
 
 
 
 
 
 
 
Income from equity method investee
 
$
—

 
$
2,298

 
$
—

 
$
2,298

Interest expense(4)
 
$
(22,303
)
 
$
(1,402
)
 
$
—

 
$
(23,705
)
Capital expenditures
 
$
(105,785
)
 
$
(1,937
)
 
$
—

 
$
(107,722
)
Gross property and equipment(5)
 
$
5,392,865

 
$
347,892

 
$
(3,078
)
 
$
5,737,679

Three months ended March 31, 2015:
 
 
 
 
 
 
 
 
Oil, NGL and natural gas sales
 
$
118,211

 
$
112

 
$
(205
)
 
$
118,118

Midstream service revenues
 
—

 
3,683

 
(2,374
)
 
1,309

Sales of purchased oil
 
—

 
31,267

 
—

 
31,267

Total revenues
 
118,211

 
35,062

 
(2,579
)
 
150,694

Lease operating expense, including production tax
 
43,845

 
—

 
(2,379
)
 
41,466

Midstream service expenses
 
—

 
3,342

 
(112
)
 
3,230

Costs of purchased oil
 
—

 
31,200

 
—

 
31,200

General and administrative(1)
 
19,778

 
2,077

 
—

 
21,855

Depletion, depreciation and amortization(2)
 
70,257

 
1,685

 
—

 
71,942

Impairment expense
 
767

 
111

 
—

 
878

Other operating costs and expenses(3)
 
6,424

 
197

 
—

 
6,621

Operating loss
 
$
(22,860
)
 
$
(3,550
)
 
$
(88
)
 
$
(26,498
)
Other financial information:
 
 
 
 
 
 
 
 
Loss from equity method investee
 
$
—

 
$
(433
)
 
$
—

 
$
(433
)
Interest expense(4)
 
$
(31,087
)
 
$
(1,327
)
 
$
—

 
$
(32,414
)
Capital expenditures
 
$
(247,613
)
 
$
(20,473
)
 
$
—

 
$
(268,086
)
Gross property and equipment(5)
 
$
5,057,149

 
$
216,345

 
$
(321
)
 
$
5,273,173

_______________________________________________________________________________
(1)
General and administrative costs were allocated based on the number of employees in the respective segment for the three months ended March 31, 2016 and 2015. Certain components of general and administrative costs were not allocated and were based on actual costs for each segment, which primarily consisted of payroll, deferred compensation and vehicle costs for the three months ended March 31, 2016 and 2015. Costs associated with land and geology were not allocated to the midstream and marketing segment for the three months ended March 31, 2016 and 2015.
(2)
Depletion, depreciation and amortization were based on actual costs for each segment with the exception of the allocation of depreciation of other fixed assets, which is based on the number of employees in the respective segment for the three months ended March 31, 2016 and 2015.
(3)
Other operating costs and expenses includes accretion of asset retirement obligations for the three months ended March 31, 2016 and restructuring expense and accretion of asset retirement obligations for the three months ended March 31, 2015. These expenses are based on actual costs and are not allocated.
(4)
Interest expense was allocated to the exploration and production segment based on gross property and equipment for the three months ended March 31, 2016 and 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee for the three months ended March 31, 2016 and 2015.

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

(5)
Gross property and equipment for the midstream and marketing segment includes investment in equity method investee totaling $194.8 million and $72.4 million as of March 31, 2016 and 2015, respectively. Other fixed assets were allocated based on the number of employees in the respective segment as of March 31, 2016 and 2015.
Note 17—Subsidiary guarantors
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 (and had guaranteed the January 2019 Notes until the Redemption Date), 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 March 31, 2016 and December 31, 2015, and unaudited condensed consolidating statements of operations and unaudited condensed consolidating statements of cash flows for the three months ended March 31, 2016 and 2015, 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. During the three months ended March 31, 2016, certain assets were transferred from LMS to Laredo at historical cost. See Note 5.d for a discussion of the early redemption of the January 2019 Notes.

Condensed consolidating balance sheet
March 31, 2016
(Unaudited)
(in thousands)
 
Laredo

Subsidiary
Guarantors

Intercompany
eliminations

Consolidated
company
Accounts receivable, net
 
$
72,730

 
$
12,443

 
$
—

 
$
85,173

Other current assets
 
194,176

 
1,509

 
—

 
195,685

Total oil and natural gas properties, net
 
908,987

 
9,341

 
(3,078
)
 
915,250

Total midstream service assets, net
 
—

 
130,007

 
—

 
130,007

Total other fixed assets, net
 
42,187

 
289

 
—

 
42,476

Investment in subsidiaries and equity method investee
 
331,788

 
194,822

 
(331,788
)
 
194,822

Total other long-term assets
 
69,899

 
3,852

 
—

 
73,751

Total assets
 
$
1,619,767

 
$
352,263

 
$
(334,866
)
 
$
1,637,164

 
 
 
 
 
 
 
 
 
Accounts payable
 
$
22,826

 
$
556

 
$
—

 
$
23,382

Other current liabilities
 
115,620

 
17,072

 
—

 
132,692

Long-term debt, net
 
1,476,890

 
—

 
—

 
1,476,890

Other long-term liabilities
 
47,069

 
2,847

 
—

 
49,916

Stockholders' (deficit) equity
 
(42,638
)
 
331,788

 
(334,866
)
 
(45,716
)
Total liabilities and stockholders' (deficit) equity
 
$
1,619,767

 
$
352,263

 
$
(334,866
)
 
$
1,637,164




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

Condensed consolidating balance sheet
December 31, 2015
(Unaudited)
(in thousands)
 
Laredo
 
Subsidiary
Guarantors
 
Intercompany
eliminations
 
Consolidated
company
Accounts receivable, net
 
$
74,613

 
$
13,086

 
$
—

 
$
87,699

Other current assets
 
244,477

 
56

 
—

 
244,533

Total oil and natural gas properties, net
 
1,017,565

 
9,350

 
(1,923
)
 
1,024,992

Total midstream service assets, net
 
—

 
131,725

 
—

 
131,725

Total other fixed assets, net
 
43,210

 
328

 
—

 
43,538

Investment in subsidiaries and equity method investee
 
301,891

 
192,524

 
(301,891
)
 
192,524

Total other long-term assets
 
84,360

 
3,916

 
—

 
88,276

Total assets
 
$
1,766,116

 
$
350,985

 
$
(303,814
)
 
$
1,813,287

 
 
 
 
 
 
 
 
 
Accounts payable
 
$
12,203

 
$
1,978

 
$
—

 
$
14,181

Other current liabilities
 
158,283

 
44,351

 
—

 
202,634

Long-term debt, net
 
1,416,226

 
—

 
—

 
1,416,226

Other long-term liabilities
 
46,034

 
2,765

 
—

 
48,799

Stockholders' equity
 
133,370

 
301,891

 
(303,814
)
 
131,447

Total liabilities and stockholders' equity
 
$
1,766,116

 
$
350,985

 
$
(303,814
)
 
$
1,813,287

 
Condensed consolidating statement of operations
For the three months ended March 31, 2016
(Unaudited)
(in thousands)

Laredo
 
Subsidiary
Guarantors
 
Intercompany
eliminations
 
Consolidated
company
Total revenues

$
73,122


$
42,901


$
(9,466
)

$
106,557

Total costs and expenses

250,064


41,592


(8,311
)

283,345

Operating income (loss)

(176,942
)

1,309


(1,155
)

(176,788
)
Interest expense and other, net

(23,606
)

—


—


(23,606
)
Other non-operating income

21,332


2,291


(3,600
)

20,023

Income (loss) before income tax

(179,216
)

3,600


(4,755
)

(180,371
)
Income tax

—


—


—


—

Net income (loss)

$
(179,216
)

$
3,600


$
(4,755
)

$
(180,371
)


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

Condensed consolidating statement of operations
For the three months ended March 31, 2015
(Unaudited)
(in thousands)
 
Laredo

Subsidiary
Guarantors

Intercompany
eliminations

Consolidated
company
Total revenues
 
$
118,146

 
$
35,127

 
$
(2,579
)
 
$
150,694

Total costs and expenses
 
143,308

 
36,375

 
(2,491
)
 
177,192

Operating loss
 
(25,162
)
 
(1,248
)
 
(88
)
 
(26,498
)
Interest expense and other, net
 
(32,291
)
 
—

 
—

 
(32,291
)
Other non-operating income (expense)
 
60,712

 
(433
)
 
1,681

 
61,960

Income (loss) before income tax
 
3,259

 
(1,681
)
 
1,593

 
3,171

Deferred income tax expense
 
(3,643
)
 
—

 
—

 
(3,643
)
Net loss
 
$
(384
)
 
$
(1,681
)
 
$
1,593

 
$
(472
)
Condensed consolidating statement of cash flows
For the three months ended March 31, 2016
(Unaudited)
(in thousands)
 
Laredo
 
Subsidiary
Guarantors
 
Intercompany
eliminations
 
Consolidated
company
Net cash flows provided by operating activities
 
$
58,163

 
$
1,954

 
$
(3,600
)
 
$
56,517

Change in investment between affiliates
 
(30,235
)
 
26,635

 
3,600

 
—

Capital expenditures and other
 
(105,575
)
 
(28,589
)
 
—

 
(134,164
)
Net cash flows provided by financing activities
 
58,588

 
—

 
—

 
58,588

Net decrease in cash and cash equivalents
 
(19,059
)
 
—

 
—

 
(19,059
)
Cash and cash equivalents at beginning of period
 
31,153

 
1

 
—

 
31,154

Cash and cash equivalents at end of period
 
$
12,094

 
$
1

 
$
—

 
$
12,095

 Condensed consolidating statement of cash flows
For the three months ended March 31, 2015
(Unaudited)
(in thousands)
 
Laredo
 
Subsidiary
Guarantors
 
Intercompany
eliminations
 
Consolidated
company
Net cash flows provided by (used in) operating activities
 
$
51,531

 
$
(26,347
)
 
$
1,681

 
$
26,865

Change in investment between affiliates
 
(59,634
)
 
61,315

 
(1,681
)
 
—

Capital expenditures and other
 
(247,578
)
 
(34,968
)
 
—

 
(282,546
)
Net cash flows provided by financing activities
 
795,453

 
—

 
—

 
795,453

Net increase in cash and cash equivalents
 
539,772

 
—

 
—

 
539,772

Cash and cash equivalents at beginning of period
 
29,320

 
1

 
—

 
29,321

Cash and cash equivalents at end of period
 
$
569,092

 
$
1

 
$
—

 
$
569,093

Note 18—Recent accounting pronouncements
In March 2016, the Financial Accounting Standards Board ("FASB") issued new guidance in Topic 718, Compensation—Stock Compensation, which seeks to simplify the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. The amendments in this update are effective for annual periods beginning after December 15, 2016 and interim periods within those annual periods. Early adoption is permitted for any entity in any interim or annual period. If an entity early adopts the amendments in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the applicable amendments in the same period. The Company is currently evaluating the impact this guidance will have on its consolidated financial statements upon adoption of this standard.

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

In February 2016, the FASB issued new guidance in Topic 842, Leases. The core principle of the new guidance is that a lessee should recognize the assets and liabilities that arise from leases in the statement of financial position. A lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. When measuring assets and liabilities arising from a lease, a lessee (and a lessor) should include payments to be made in optional periods only if the lessee is reasonably certain to exercise an option to extend the lease or not to exercise an option to terminate the lease. Similarly, optional payments to purchase the underlying asset should be included in the measurement of lease assets and lease liabilities only if the lessee is reasonably certain to exercise that purchase option. Reasonably certain is a high threshold that is consistent with and intended to be applied in the same way as the reasonably assured threshold in the previous leases guidance. In addition, also consistent with the previous leases guidance, a lessee (and a lessor) should exclude most variable lease payments in measuring lease assets and lease liabilities, other than those that depend on an index or a rate or are in substance fixed payments. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities. If a lessee makes this election, it should recognize lease expense for such leases generally on a straight-line basis over the lease term. The recognition, measurement and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from previous GAAP. There continues to be a differentiation between finance leases and operating leases. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. These practical expedients relate to the identification and classification of leases that commenced before the effective date, initial direct costs for leases that commenced before the effective date and the ability to use hindsight in evaluating lessee options to extend or terminate a lease or to purchase the underlying asset. An entity that elects to apply the practical expedients will, in effect, continue to account for leases that commence before the effective date in accordance with previous GAAP unless the lease is modified, except that lessees are required to recognize a right-of-use asset and a lease liability for all operating leases at each reporting date based on the present value of the remaining minimum rental payments that were tracked and disclosed under previous GAAP. The amendments in this update are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application of the amendments in this update is permitted. The Company is currently evaluating the impact this guidance will have on its consolidated financial statements upon adoption of this standard.
In July 2015, the 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 350-40, Intangibles—Goodwill and Other—Internal-Use Software. The amendments in this update provide guidance to customers about whether a cloud computing arrangement includes a software license. If a cloud computing arrangement includes a software license, then the customer should account for the software license element of the arrangement consistent with the acquisition of other software licenses. If a cloud computing arrangement does not include a software license, the customer should account for the arrangement as a service contract. The guidance will not change GAAP for a customer's accounting for service contracts. In addition, the guidance in this update supersedes paragraph 350-40-25-16. The amendments in this update are effective for annual periods beginning after December 15, 2015, including interim periods within those annual periods and should be applied prospectively to all arrangements entered into or materially modified after the effective date or retrospectively. The Company elected to adopt this guidance in the first quarter of 2016 on a prospective basis, and the adoption did not have an effect on its unaudited consolidated financial statements.
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

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

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.
Note 19—Subsequent events
a.   Senior Secured Credit Facility
On April 1, 2016, the Company borrowed $15.0 million on the Senior Secured Credit Facility. The outstanding balance under the Senior Secured Credit Facility was $210.0 million as of May 3, 2016. Additionally, effective May 2, 2016, in connection with the regular semi-annual redetermination of the borrowing base under the Senior Secured Credit Facility, the borrowing base and aggregate elected commitment were each reduced to $815.0 million.
b.  Medallion contribution
On April 15, 2016, the Company contributed $0.9 million to fund continued expansion activities on existing portions of Medallion's pipeline infrastructure in order to gather additional third-party production. As of March 31, 2016, the Company had recorded a capital contribution payable for the amount of this capital call. See Note 14 for additional discussion regarding Medallion and see Note 15.a for discussion of items included in the Company's unaudited consolidated financial statements related to Medallion.    
c.    New derivative contracts
Subsequent to March 31, 2016, the Company entered into the following new derivative contracts:
 
 
Aggregate
volumes
 
Floor price
 
Ceiling price
 
Contract period
Oil (volumes in Bbl):(1)
 
 
 
 
 
 
 
 
Put
 
600,000

 
$
40.00

 
$
—

 
May 2016 - December 2016
Natural gas (volumes in MMBtu):(2)
 
 
 
 
 
 
 
 
Collar
 
5,256,000

 
$
2.50

 
$
3.05

 
January 2017 - December 2017
Collar
 
4,635,500

 
$
2.50

 
$
3.60

 
January 2018 - December 2018
_____________________________________________________________
(1)
The associated derivative will be settled based on the WTI NYMEX index oil price. There are $1.2 million in deferred premiums associated with this contract.
(2)
The associated derivatives will be settled based on the Inside FERC index price for West Texas Waha. There are $0.8 million in deferred premiums associated with these contracts.
d.   Leasehold acquisition
Subsequent to March 31, 2016, the Company acquired or entered into agreements to acquire 1,114 net acres of additional leasehold interests in Glasscock county within the Company's core development area, for an aggregate purchase price of $10.8 million.



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

Note 20—Supplementary information
Costs incurred in oil, NGL and natural gas property acquisition, exploration and development activities
Costs incurred in the acquisition, exploration and development of oil, NGL and natural gas assets are presented below:
 
 
Three months ended March 31,
(in thousands)
 
2016
 
2015
Property acquisition costs:
 
 

 
 

Evaluated
 
$
—

 
$
—

Unevaluated
 
—


—

Exploration
 
7,263


4,513

Development costs(1)
 
81,886


206,672

Total costs incurred
 
$
89,149


$
211,185

____________________________________________________________________________
(1)
The costs incurred for oil, NGL and natural gas development activities include $0.1 million and $0.5 million in asset retirement obligations for the three months ended March 31, 2016 and 2015, 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 2015 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 refer to Laredo, LMS and GCM 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, and the transportation of oil and natural gas from such properties, primarily 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 March 31, 2016 included the following:
•
Oil, NGL and natural gas sales of $73.1 million, compared to $118.1 million for the three months ended March 31, 2015;
•
Average daily sales volumes of 46,202 BOE/D, compared to 47,487 BOE/D for the three months ended March 31, 2015;
•
Net loss of $180.4 million, including a non-cash full cost ceiling impairment of $161.1 million, compared to net loss of $0.5 million for the three months ended March 31, 2015; and
•
Adjusted EBITDA (a non-GAAP financial measure) of $96.1 million, compared to $118.6 million for the three months ended March 31, 2015.
Reserves, pricing and non-cash full cost ceiling impairment
Our results of operations are heavily influenced by oil, NGL and natural gas prices, which have significantly declined and remain at low levels. Oil, NGL and natural gas price fluctuations are caused by changes in global and regional supply and demand, market uncertainty, economic conditions and a variety of additional factors. Since the inception of our oil and natural gas activities, commodity prices have experienced significant fluctuations, and additional changes in commodity prices may affect the economic viability of, and our ability to fund, our drilling projects, as well as the economic valuation and economic recovery of oil, NGL and natural gas reserves.
Our reserves as of March 31, 2016 and December 31, 2015 are reported in three streams: oil, NGL and natural gas. Net book value of evaluated oil and natural gas properties exceeded the full cost ceiling amount as of March 31, 2016. As such, we recorded a first-quarter non-cash full cost ceiling impairment of $161.1 million. See Note 2.f to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for prices used to value our reserves and additional discussion of our full cost impairment.
We have entered into a number of derivatives, which have enabled us to offset a portion of the changes in our cash flow caused by price fluctuations on our sales of oil, NGL and natural gas as discussed in "Item 3. Quantitative and Qualitative Disclosures About Market Risk."
Potential future low commodity price impact on our full cost impairment
Oil, NGL and natural gas prices have remained low in the second quarter of 2016. If prices remain at or below the current low levels, subject to numerous factors and inherent limitations, and if all other factors remain constant, we will incur an additional non-cash full cost impairment in the second quarter of 2016, which will have an adverse effect on our results of operations.
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

37

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 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.
We have set forth below a calculation of a potential future full cost impairment. Such implied impairment 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 second-quarter effects. Based on such review, we determined that (i) the impact of decreased commodity prices, (ii) changes in cost estimates and (iii) changes in reserves are the only significant known variables necessary in the following scenario.
Our hypothetical second-quarter 2016 full cost ceiling calculation has been prepared (i) by substituting (a) $37.96 per barrel for oil, (b) $10.85 per barrel for NGL and (c) $1.61 per MMBtu for natural gas (the "Pro Forma Prices") for the respective Realized Prices as of March 31, 2016 and (ii) by incorporating a reduction in lease operating costs of 1%, updated drilling and completion costs and changes in our reserves. All other inputs and assumptions have been held constant. The Pro Forma Prices use a slightly modified Realized 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 May 1, 2016, with the price for May 1, 2016 held constant for the remaining twelfth month of the calculation. Based on these inputs, the implied second-quarter impairment would be $21 million. We believe that substituting the Pro Forma Prices and updating our cost and reserve estimates in our March 31, 2016 internal reserve estimates may help provide users with an understanding of the impact of known trends on our June 30, 2016 full cost ceiling test and in preparing our year-end reserve estimates.
Recent developments
Borrowing base redetermination under the Senior Secured Credit Facility
Effective May 2, 2016, in connection with our regular semi-annual redetermination of the borrowing base under the Senior Secured Credit Facility, the borrowing base and aggregate elected commitment amounts were each reduced to $815.0 million. For more information regarding the borrowing base redetermination, see Notes 5.e and 19.a 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 March 31, 2016, we had assembled 132,676 net acres in the Permian Basin.
Sources of our revenue
Our revenues are primarily derived from the sale of oil, NGL and natural gas within the continental United States and the sale of purchased oil and do not include the effects of derivatives. For the three months ended March 31, 2016, our revenues were comprised of sales of 52% oil, 8% NGL, 8% natural gas, 30% sales of purchased oil and 2% 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 sales of purchased oil revenue may vary due to changes in oil prices. Our midstream service revenues may vary due to oil throughput fees and the level of services provided to third parties for (i) gathered natural gas, (ii) gas lift fees and (iii) water services.

38

Results of operations consolidated
Three months ended March 31, 2016 as compared to the three months ended March 31, 2015
Oil, NGL and natural gas sales volumes, revenues and pricing
The following table sets forth information regarding oil, NGL and natural gas sales volumes, revenues and average sales prices per BOE sold, for the periods presented:
 
 
Three months ended March 31,
 
 
2016
 
2015
Sales volumes:
 
 


 

Oil (MBbl)
 
2,006


2,172

NGL (MBbl)
 
1,066

 
989

Natural gas (MMcf)
 
6,796


6,680

Oil equivalents (MBOE)(1)(2)
 
4,204


4,274

Average daily sales volumes (BOE/D)(2)
 
46,202


47,487

% Oil
 
48
%

51
%
Oil, NGL and natural gas revenues (in thousands):
 



 
Oil
 
$
55,194


$
90,615

NGL
 
9,052

 
13,187

Natural gas
 
8,896


14,316

Total
 
$
73,142


$
118,118

Average sales prices:
 



 
Oil, realized ($/Bbl)(3)
 
$
27.51


$
41.73

NGL, realized ($/Bbl)(3)
 
$
8.50


$
13.34

Natural gas, realized ($/Mcf)(3)
 
$
1.31


$
2.14

Average price, realized ($/BOE)(3)
 
$
17.40


$
27.64

Oil, hedged ($/Bbl)(4)
 
$
56.84


$
69.51

NGL, hedged ($/Bbl)(4)
 
$
8.50


$
13.34

Natural gas, hedged ($/Mcf)(4)
 
$
2.08


$
2.35

Average price, hedged ($/BOE)(4)
 
$
32.64


$
42.08

________________________________________________________________________
(1)
BOE equivalents are calculated using a conversion rate of six Mcf per one Bbl.
(2)
The volumes presented are based on actual results and are not calculated using the rounded numbers presented in the table above.
(3)
Realized oil, NGL and natural gas prices are the actual prices realized at the wellhead adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. The prices presented are based on actual results and are not calculated using the rounded numbers presented in the table above.
(4)
Hedged prices reflect the after-effect of our hedging transactions on our average sales prices. Our calculation of such after-effects include current period settlements of matured 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.
    

39

The following table presents cash settlements received for matured derivatives and premiums incurred previously or upon settlement attributable to instruments that settled during the periods utilized in our calculation of the hedged prices presented above:        
 
 
Three months ended March 31,
(in thousands)
 
2016
 
2015
Cash settlements received for matured derivatives:
 





Oil
 
$
60,692


$
61,586

Natural gas
 
5,245


1,555

Total
 
$
65,937


$
63,141

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





Oil
 
$
(1,850
)

$
(1,245
)
Natural gas
 
—


(176
)
Total
 
$
(1,850
)

$
(1,421
)
 
Changes in prices and volumes caused the following changes to our oil, NGL and natural gas revenues between the three months ended March 31, 2016 and 2015:
(in thousands)
 
Oil
 
NGL
 
Natural gas
 
Total net dollar
effect of change
2015 Revenues
 
$
90,615

 
$
13,187

 
$
14,316


$
118,118

Effect of changes in price
 
(28,514
)
 
(5,157
)
 
(5,670
)
 
(39,341
)
Effect of changes in volumes
 
(6,907
)
 
1,022

 
250

 
(5,635
)
2016 Revenues
 
$
55,194

 
$
9,052

 
$
8,896

 
$
73,142

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 $35.4 million, or 39%, for the three months ended March 31, 2016 as compared to the three months ended March 31, 2015, is mainly due to a 34% decrease in average oil prices realized and a 8% decrease in oil production.
NGL and natural gas revenues. 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 decrease in NGL revenue of $4.1 million, or 31%, for the three months ended March 31, 2016 as compared to the three months ended March 31, 2015, is mainly due to a 36% decrease in average NGL prices realized. The decrease in natural gas revenue of $5.4 million, or 38%, for the three months ended March 31, 2016 as compared to the three months ended March 31, 2015, is mainly due to a 39% decrease in average natural gas prices realized.

40


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 March 31,
(in thousands except for per BOE sold data)
 
2016
 
2015
Costs and expenses:
 
 

 
 

Lease operating expenses
 
$
20,518

 
$
32,380

Production and ad valorem taxes
 
6,435

 
9,086

Midstream service expenses
 
609

 
1,574

Minimum volume commitments
 
—

 
1,656

Costs of purchased oil
 
32,946

 
31,200

General and administrative(1)
 
19,451

 
21,855

Restructuring expenses
 
—

 
6,042

Accretion of asset retirement obligations
 
844

 
579

Depletion, depreciation and amortization
 
41,478

 
71,942

Impairment expense
 
161,064

 
878

Total
 
$
283,345

 
$
177,192

Average costs per BOE sold:






Lease operating expenses

$
4.88


$
7.58

Production and ad valorem taxes
 
1.53

 
2.13

Midstream service expenses
 
0.14

 
0.37

General and administrative(1)
 
4.63


5.11

Depletion, depreciation and amortization
 
9.87


16.83

Total
 
$
21.05


$
32.02

________________________________________________________________________
(1)
General and administrative includes non-cash stock-based compensation, net of amounts capitalized, of $3.8 million and $4.8 million for the three months ended March 31, 2016 and 2015, respectively.
Lease operating expenses. Lease operating expenses, which include workover expenses, decreased by $11.9 million, or 37%, for the three months ended March 31, 2016 as compared to the same period in 2015. Previous investments in field infrastructure, primarily in our four production corridors, including water takeaway and recycling facilities and centralized compression, lowered costs and reduced well downtime. We continue to focus on the usage and procurement of products and services related to direct operating costs.
Production and ad valorem taxes. Production and ad valorem taxes decreased by $2.7 million, or 29%, for the three months ended March 31, 2016 as compared to the same period in 2015. This change is mainly due to a decrease in production taxes of $2.2 million for the three months ended March 31, 2016 compared to the same period in 2015 as a result of the corresponding decrease in oil, NGL and natural gas revenues. Production taxes are based on and fluctuate in proportion to our oil, NGL and natural gas revenue.
Midstream service expenses. See "—Results of operations - midstream and marketing" for a discussion of these costs.
Minimum volume commitments. See "—Results of operations - midstream and marketing" for a discussion of these costs.
Costs of purchased oil. See "—Results of operations - midstream and marketing" for a discussion of these costs.
    

41


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 March 31, 2016 compared to 2015
Changes in G&A:
 
 
Performance unit awards
 
$
(996
)
Stock-based compensation, net of amounts capitalized
 
(950
)
Professional fees
 
(390
)
Other
 
(68
)
Total changes in G&A
 
$
(2,404
)
G&A expense, excluding stock-based compensation, decreased by $1.5 million, or 9%, for the three months ended March 31, 2016 compared to the same period in 2015. This decrease is primarily related to our performance unit awards, which prior to their payouts, were accounted for as liability awards. The associated expense for these awards decreased by $1.0 million for the three months ended March 31, 2016 compared to the same period in 2015. This fluctuation is due to the 2013 Performance Unit Awards performance criteria being satisfied at December 31, 2015, and the awards being paid at $143.75 per unit during the first quarter of 2016. As the 2013 Performance Unit Awards were fully accrued at December 31, 2015, no additional expense was recorded during the three months ended March 31, 2016. There are no outstanding awards of this type at March 31, 2016.
An additional contributor to the decrease in G&A expense, excluding stock-based compensation, is a decrease in professional fees of $0.4 million for the three months ended March 31, 2016 compared to the same period in 2015. This decrease is primarily due to our March 2015 Equity Offering and the issuance of our March 2023 Notes that occurred during the three months ended March 31, 2015. No comparable offerings were made during the three months ended March 31, 2016.
Stock-based compensation, net of amounts capitalized, decreased by $1.0 million, or 20%, for the three months ended March 31, 2016 compared to the same period in 2015. During the three months ended March 31, 2015 we issued 1,748,517 restricted stock awards at a weighted-average grant price of $11.90 per share to new and existing employees and non-employee directors. During the three months ended March 31, 2016, restricted stock awards, restricted stock options and performance share awards were approved by our compensation committee; however, these awards are contingent and subject to stockholder approval of the Amendment to the LTIP at our 2016 Annual Meeting of Stockholders on May 25, 2016. These awards are not considered granted for accounting purposes until such Amendment is approved by our stockholders; as such, no expense has been recorded for these contingent awards during the three months ended March 31, 2016. For further discussion of our stock-based compensation, see Note 6 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.
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 and are included in stock-based compensation expense. 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.
See Notes 2.m 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 that was undertaken to reduce costs and better position ourselves for future operations in a low commodity price environment. Restructuring expenses of $6.0 million were incurred during the three months ended March 31, 2015. No comparable expenses were recorded during the three months ended March 31, 2016. See Note 13 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for further discussion of the RIF.

42


Depletion, depreciation and amortization ("DD&A"). The following table provides components of our DD&A expense for the periods presented:
 
 
Three months ended March 31,
(in thousands except for per BOE sold data)
 
2016
 
2015
Depletion of evaluated oil and natural gas properties
 
$
37,827

 
$
68,728

Depreciation of midstream service assets
 
2,071

 
1,647

Depreciation and amortization of other fixed assets
 
1,580

 
1,567

Total DD&A
 
$
41,478

 
$
71,942

DD&A per BOE sold
 
$
9.87

 
$
16.83

DD&A decreased by $30.5 million, or 42%, for the three months ended March 31, 2016 compared to the same period in 2015, mainly due to our full cost ceiling impairments totaling $2.4 billion during the year ended December 31, 2015. We expect DD&A per BOE will further decrease in the second quarter of 2016 due to our first-quarter 2016 impairment.
Impairment expense. Our net book value of evaluated oil and natural gas properties exceeded the full cost ceiling amount as of March 31, 2016. As a result, we recorded a first-quarter 2016 non-cash full cost ceiling impairment of $161.1 million. There was no comparable full cost impairment during the same period in 2015. For further discussion of our non-cash full cost celling impairments, see Note 2.f to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.
Non-operating income and expense. The following table sets forth the components of non-operating income and expense for the periods presented:
 
 
Three months ended March 31,
(in thousands)
 
2016
 
2015
Non-operating income (expense):
 
 

 
 

Gain on derivatives, net
 
$
17,885

 
$
63,155

Income (loss) from equity method investee
 
2,298

 
(433
)
Interest expense
 
(23,705
)
 
(32,414
)
Interest and other income
 
99

 
123

Loss on disposal of assets, net
 
(160
)
 
(762
)
Non-operating income (expense), net
 
$
(3,583
)
 
$
29,669

Gain on derivatives, net. The table below shows the changes in the components of gain on derivatives, net for the periods presented:
(in thousands)
 
Three months ended March 31, 2016 compared to 2015
Changes in gain on derivatives, net:
 
 
Fair value of derivatives outstanding
 
$
(128,066
)
Early terminations of derivatives received
 
80,000

Cash settlements received for matured derivatives
 
2,796

Total changes in gain on derivatives, net
 
$
(45,270
)
The change in fair value of derivatives outstanding for the three months ended March 31, 2016 compared to the same period in 2015 is the result of the changing relationship between our outstanding 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 on derivatives, net for the three months ended March 31, 2016 compared to 2015 was partially offset by proceeds received in a hedge restructuring in which we early terminated floors of certain derivative contract collars, resulting in a termination amount due to us of $80.0 million. The $80.0 million was settled in full by applying the proceeds to the premiums on two new derivatives entered into as part of the hedge restructuring. 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.

43


Income (loss) from equity method investee. Income from equity method investee increased by $2.7 million for the three months ended March 31, 2016 compared to the same period in 2015. During the three months ended March 31, 2016, Medallion, our equity method investee, continued expansion activities on existing portions of its pipeline infrastructure in order to gather additional third-party oil production. Medallion began recognizing revenue during the first quarter of 2015 due to its main pipeline becoming fully operational. The Medallion pipeline system transported more than 83,000 barrels of oil per day ("BOPD") during the three months ended March 31, 2016 compared to more than 10,000 BOPD in the time that the system was operational during the three months ended March 31, 2015.
Interest expense. The table below shows the changes in the significant components of interest expense for the periods presented:
(in thousands)
 
Three months ended March 31, 2016 compared to 2015
Changes in interest expense:
 
 

January 2019 Notes
 
$
(12,998
)
March 2023 Notes
 
4,679

Senior Secured Credit Facility, net of capitalized interest
 
(226
)
Other
 
(164
)
Total change in interest expense
 
$
(8,709
)
Interest expense decreased by $8.7 million, or 27%, for the three months ended March 31, 2016 compared to the same period in 2015. This decrease is primarily due to the early redemption of the January 2019 Notes on April 6, 2015, which is 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.
Loss on disposal of assets, net. Loss on disposal of assets, net decreased $0.6 million for the three months ended March 31, 2016 compared to the same period in 2015 as a result of lower losses related to the sales of materials and supplies and other fixed assets during 2016 as compared to 2015.
Income tax expense. The fluctuations in net income (loss) before income tax expense are shown in the table below:
 
 
Three months ended March 31,
(in thousands)
 
2016
 
2015
Income (loss) before income taxes
 
$
(180,371
)
 
$
3,171

Income tax expense
 
—

 
(3,643
)
Net loss
 
$
(180,371
)
 
$
(472
)
Our effective tax rate is affected by changes in valuation allowances, recurring permanent differences and by discrete items that may occur in any given year, but are not consistent from year to year. For the three months ended March 31, 2016, the effective tax rate on loss before income taxes was not meaningful due to the valuation allowance recorded. For the three months ended March 31, 2015, the effective tax rate on income before income taxes was not meaningful due to the significant effect of discrete items on a relatively small amount of income. For the three months ended March 31, 2016, we recorded an additional valuation allowance of $57.7 million for our deferred tax assets due to uncertainty regarding their realization. For further discussion of our valuation allowance, see Note 7 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.
During the three months ended March 31, 2016 and 2015, certain shares related to restricted stock awards vested at times when the Company's stock price was lower than the fair value of those shares at the time of the grant. As a result, the income tax deduction related to such shares is less than the expense previously recognized for book purposes. During the three months ended March 31, 2016 and 2015, no restricted stock options were exercised. As a result of these differences in book compensation cost and related tax deduction, the tax impact of these shortfalls increased by $1.4 million for the three months ended March 31, 2016 compared to the same period in 2015.
We utilize a one-pool approach when accounting for the pool of windfall tax benefits in which employees and non-employees are grouped into a single pool. As of March 31, 2016 and 2015, 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

44


impact because of dependency upon the future market price of our stock. See Notes 6.a, 6.b and 7 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information.
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 March 31,
(in thousands)
 
2016
 
2015
Natural gas sales
 
$
—

 
$
112

Midstream service revenues
 
11,267

 
3,683

Sales of purchased oil
 
31,614

 
31,267

Total revenues
 
42,881

 
35,062

Midstream service expenses, including minimum volume commitments
 
6,509

 
3,342

Costs of purchased oil
 
32,946

 
31,200

General and administrative(1)
 
1,772

 
2,077

Depreciation and amortization(2)
 
2,186

 
1,685

Other operating costs and expenses(3)
 
52

 
308

Operating loss
 
$
(584
)
 
$
(3,550
)
Other financial information:
 
 
 
 
Income (loss) from equity method investee
 
$
2,298

 
$
(433
)
Interest expense(4)
 
$
(1,402
)
 
$
(1,327
)
_______________________________________________________________________________
(1)
G&A was allocated based on the number of employees in the midstream and marketing segment for the three months ended March 31, 2016 and 2015. Certain components of G&A were not allocated and were based on actual costs to the midstream and marketing segment which primarily consisted of payroll, deferred compensation and vehicle costs for the three months ended March 31, 2016 and 2015. Costs associated with land and geology were not allocated to the midstream and marketing segment for the three months ended March 31, 2016 and 2015.
(2)
Depreciation and amortization was based on actual costs for the midstream and marketing segment with the exception of the allocation of other fixed asset depreciation, which was based on the number of employees in the midstream and marketing segment for the three months ended March 31, 2016 and 2015.
(3)
Other operating costs and expenses includes accretion of asset retirement obligations for the three months ended March 31, 2016 and restructuring expense, accretion of asset retirement obligations and impairment expense for the three months ended March 31, 2015. These expenses are based on actual costs to the midstream and marketing segment and are not allocated.
(4)
Interest expense was allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee for the three months ended March 31, 2016 and 2015.
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." See Note 16 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information on the operating segments.
Midstream service revenues. Our midstream service revenues from operations increased by $7.6 million during the three months ended March 31, 2016 compared to the same period in 2015. This increase is mainly due to (i) water service revenue that we began recognizing in the third quarter of 2015 and (ii) an increase in volumes of natural gas provided for natural gas lift mainly in our production corridors over the prior period.
Sales of purchased oil. Sales of purchased oil was $31.6 million and $31.3 million for the three months ended March 31, 2016 and 2015, respectively. We purchase oil from producers in West Texas, transport the product on the Bridgetex Pipeline and sell the product to a third party in the Houston market.
Midstream service expenses, including minimum volume commitments. Midstream service expenses, including minimum volume commitments in 2015, increased by $3.2 million for the three months ended March 31, 2016 compared to the

45


same period in 2015. Midstream service expenses primarily 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, (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 was $32.9 million and $31.2 million for the three months ended March 31, 2016 and 2015, respectively. These costs include purchasing oil from producers and transporting the purchased oil on the Bridgetex Pipeline to the Houston market.
G&A. Our consolidated G&A expense has decreased for the three months ended March 31, 2016 compared to the same period in 2015. See "—Results of operations consolidated" for a discussion of these costs.
Depreciation and amortization. Depreciation and amortization increased by $0.5 million for the three months ended March 31, 2016 compared to the same period in 2015 due to the continued expansion of our midstream service infrastructure.
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." During the year ended December 31, 2015, Medallion began recognizing revenue due to its main pipeline becoming fully operational. See Note 14 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information regarding this investment.
Interest expense. Interest expense increased by $0.1 million for three months ended March 31, 2016 compared to the same period in 2015. Interest is allocated to the midstream and marketing segment based on its gross property and equipment and life-to-date contributions to its equity method investee. We have expanded the midstream and marketing component of our business and built out our service facilities in the past year, thereby increasing the interest expense that is allocated to this segment. The increase is slightly offset by a significant decrease in our consolidated interest expense. See "—Results of operations consolidated" for a discussion of this decrease.
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, borrowings under our Senior Secured Credit Facility and proceeds from asset dispositions. We believe cash flows from operations (including our hedging program) 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. Our primary operational uses of capital have been for the acquisition, exploration and development of oil and natural gas properties, LMS' infrastructure development and investments in Medallion.
A significant portion of our capital expenditures can be adjusted and managed by us. We continually monitor the capital markets and our capital structure and consider which financing alternatives, including equity and debt capital resources, joint ventures and asset sales, are available to meet our future planned or accelerated capital expenditures. We may make changes to our capital structure from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity and/or achieving cost efficiency. Such financing alternatives, including capital market transactions and debt repurchases, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
We continually seek to maintain a financial profile that provides operational flexibility. However, as evidenced by the decline in our Realized Prices used in our reserves compared to the prior year, 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 May 3, 2016, we had $605.0 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 2016 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 May 4, 2016, approximately 100% of our anticipated oil production for the last nine months of 2016 is hedged at a weighted-average floor price of $67.48 per Bbl and approximately 75% of our anticipated natural gas and NGL production for the last nine months of 2016 is hedged at a weighted-average floor price of $3.00 per MMBtu.
    

46


The following table summarizes our hedge positions that were in place for the calender years presented:
 
 
Remaining year
2016
 
Year
2017
 
Year
2018
Oil positions:(1)(2)
 
 

 
 
 
 

Total volume hedged with floor price (Bbl)
 
5,498,250

 
3,677,375

 
1,049,375

Weighted-average floor price ($/Bbl)
 
$
67.48

 
$
60.00

 
$
60.00

Natural gas positions:(1)(3)
 
 

 
 

 
 

Total volume hedged with floor price (MMBtu)
 
14,025,000

 
18,771,000

 
12,855,500

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

 
$
2.65

 
$
2.50

_______________________________________________________________________________
(1)
Includes derivatives entered into subsequent to March 31, 2016.
(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.
The following table presents a projection of estimated cash received in future periods from oil and natural gas derivative contracts in place as of March 31, 2016 adjusted for any new hedge transactions entered into between April 1, 2016 and May 4, 2016, utilizing the total volumes hedged with a floor price and the weighted-average floor price for the periods presented:
(in thousands)
 
Remaining year
2016
 
Year
2017
 
Year
2018
Projected oil and natural gas hedge cash proceeds(1)
 
$
159,235

 
$
84,394

 
$
28,132

_______________________________________________________________________________
(1)
For this illustration we utilized the April 26, 2016 WTI index oil spot price of $40.50 held constant for all periods presented and the April 26, 2016 Waha natural gas spot price of $1.74 held constant for all periods presented. Additionally, we reduced our projected oil and natural gas hedge cash proceeds by the actual cash payments required for deferred premiums for the calendar years presented.
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 purchase price of $65.5 million. After transaction costs reflecting an economic effective date of July 1, 2015, the net proceeds were $64.8 million, net of working capital adjustments and 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 March 31, 2016, we had $195.0 million outstanding under our Senior Secured Credit Facility and $1.3 billion in senior unsecured notes. Prior to the semi-annual redetermination of the borrowing base under our Senior Secured Credit Facility, we had $805.0 million available for borrowings under our Senior Secured Credit Facility and $12.1 million in cash on hand for total available liquidity of $817.1 million as of March 31, 2016.
As of May 3, 2016, we had $1.5 billion in debt outstanding, $605.0 million available for borrowings under the redetermined borrowing base under our Senior Secured Credit Facility and $7.3 million in cash on hand for total available liquidity of $612.3 million. A continued decline in oil and natural gas prices will negatively impact our future borrowing base redeterminations. See “Part II, Item 5. Other Information-Item 1.01 Entry into a material definitive agreement” below for additional information regarding the reduction in the borrowing base and aggregate elected commitment amounts under our Senior Secured Credit Facility.

47


Our derivative positions will help us stabilize a portion of our expected cash flows from operations in the event of 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:
 
 
Three months ended March 31,
(in thousands)
 
2016
 
2015
Net cash provided by operating activities
 
$
56,517

 
$
26,865

Net cash used in investing activities
 
(134,164
)
 
(282,546
)
Net cash provided by financing activities
 
58,588

 
795,453

Net (decrease) increase in cash and cash equivalents
 
$
(19,059
)
 
$
539,772

Cash flows provided by operating activities
Net cash provided by operating activities was $56.5 million and $26.9 million for the three months ended March 31, 2016 and 2015, respectively. The increase of $29.7 million during the three months ended March 31, 2016 compared to the same period in 2015 was largely due to the price related decrease in oil, NGL and natural gas revenue; however, notable cash flow changes consist of (i) an increase in impairment expense of $160.2 million, (ii) a decrease in depletion, depreciation and amortization expense of $30.5 million and (iii) an increase in working capital changes of $45.0 million.
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 $134.2 million and $282.5 million for the three months ended March 31, 2016 and 2015, respectively. The decrease of $148.4 million is mainly attributable to a $138.6 million decrease in capital expenditures for oil and natural gas properties and a $18.5 million decrease in capital expenditures for midstream service assets. These changes were partially offset by a $12.2 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:
 
 
Three months ended March 31,
(in thousands)
 
2016
 
2015
Capital expenditures:
 
 
 
 
Oil and natural gas properties
 
$
(105,155
)
 
$
(243,733
)
Midstream service assets
 
(1,937
)
 
(20,434
)
Other fixed assets
 
(630
)
 
(3,919
)
Investment in equity method investee
 
(26,660
)
 
(14,495
)
Proceeds from dispositions of capital assets, net of costs
 
218

 
35

Net cash used in investing activities
 
$
(134,164
)
 
$
(282,546
)
Capital expenditure budget
Our board of directors approved a capital expenditure budget of approximately $345.0 million for calendar year 2016, excluding acquisitions and investments in Medallion. We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted. Since we do not direct the expansion activities of Medallion as a 49% owner, we cannot predict future capital commitments.
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

48


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.
Cash flows provided by financing activities
Net cash provided by financing activities were $58.6 million and $795.5 million for the three months ended March 31, 2016 and 2015, respectively. For the three months ended March 31, 2016, our primary sources of cash provided by financing activities were borrowings on our Senior Secured Credit Facility, partially offset by payments on our Senior Secured Credit Facility. For the three months ended March 31, 2015, our primary sources of cash provided by financing activities were the issuance of our March 2023 Notes and proceeds from our March 2015 Equity Offering, partially offset by our payment in full of our Senior Secured Credit Facility.
Our cash provided by financing activities for the periods presented is summarized in the table below:
 
 
Three months ended March 31,
(in thousands)
 
2016
 
2015
Borrowings on Senior Secured Credit Facility
 
$
85,000

 
$
175,000

Payments on Senior Secured Credit Facility
 
(25,000
)
 
(475,000
)
Issuance of March 2023 Notes
 
—

 
350,000

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

 
754,163

Purchase of treasury stock
 
(1,412
)
 
(2,283
)
Payments for debt issuance costs
 
—

 
(6,427
)
Net cash provided by financing activities
 
$
58,588

 
$
795,453

Debt
As of March 31, 2016, we were a party only to our Senior Secured Credit Facility and the indentures governing our senior unsecured notes.
Senior Secured Credit Facility. As of March 31, 2016, our Senior Secured Credit Facility, which matures November 4, 2018, had a maximum credit amount of $2.0 billion, a borrowing base of $1.15 billion, an aggregate elected commitment amount of $1.0 billion and $195.0 million outstanding.
The borrowing base under our Senior Secured Credit Facility is subject to a semi-annual redetermination based on the lenders' evaluation of our oil, NGL and natural gas reserves. The lenders have the right to call for an interim redetermination of the borrowing base once between any two redetermination dates and in other specified circumstances. Effective May 2, 2016, in connection with the lenders' regular semi-annual redetermination of the borrowing base, the borrowing base and aggregate elected commitment amounts were each reduced to $815.0 million. See "Part II, Item 5. Other Information-Item 1.01 Entry into a material definitive agreement" below for additional information regarding the reduction in the borrowing base and aggregate elected commitment under our Senior Secured Credit Facility.
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 based 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 certain of 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 March 31, 2016 and expect to be in compliance with them for the foreseeable future.

49


Senior unsecured notes. The following table presents principal amounts and applicable interest rates for our outstanding senior unsecured notes as of March 31, 2016:
(in millions, except for interest rates)
 
Principal
 
Interest rate
January 2022 Notes
 
$
450.0

 
5.625
%
May 2022 Notes
 
$
500.0

 
7.375
%
March 2023 Notes
 
$
350.0

 
6.250
%
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 5 of our audited consolidated financial statements included in the 2015 Annual Report and Notes 5 and 19 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 May 3, 2016, we had a total of $1.3 billion of senior unsecured notes outstanding and $210.0 million outstanding on the Senior Secured Credit Facility.
Obligations and commitments
As of March 31, 2016, our contractual obligations included our March 2023 Notes, January 2022 Notes, May 2022 Notes, Senior Secured Credit Facility, drilling contract commitments, firm sale and transportation commitments, derivative deferred premiums, asset retirement obligations, office and equipment leases and capital contribution commitments to our equity method investee. From December 31, 2015 to March 31, 2016, the material changes in our contractual obligations included (i) an increase of $60.0 million outstanding on our Senior Secured Credit Facility, (ii) a decrease of $23.6 million on our interest obligations for our senior unsecured notes as semi-annual interest payments were made in January and March of 2016, (iii) a decrease of $13.8 million in our firm sale and transportation commitments, (iv) a decrease of $26.7 million in our outstanding capital contribution commitment to our equity method investee due to payments made to Medallion during first-quarter 2016, (v) a decrease of $6.8 million for drilling contract commitments (on contracts other than those on a well-by-well basis) and (vi) a decrease of $6.4 million in our performance unit liability awards as the 2013 Performance Unit Awards were paid in first-quarter 2016.
Refer to Notes 2, 5, 6, 8, 9, 12, 14 and 15 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional discussion of our contractual obligations.
Non-GAAP financial measures
The non-GAAP financial measure of Adjusted EBITDA, as defined by us, may not be comparable to similarly titled measures used by other companies. Therefore, this non-GAAP measure should be considered in conjunction with 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 deferred 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 received for matured derivatives, cash settlements received for early terminations of derivatives, premiums paid for derivatives, 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;

50


•
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.
The following presents a reconciliation of net loss to Adjusted EBITDA:
 
 
Three months ended March 31,
(in thousands)
 
2016

2015
Net loss
 
$
(180,371
)

$
(472
)
Plus:
 





Deferred income tax expense
 
—


3,643

Depletion, depreciation and amortization
 
41,478


71,942

Impairment expense

161,064


878

Non-cash stock-based compensation, net of amounts capitalized
 
3,838


4,788

Restructuring expenses
 
—

 
6,042

Gain on derivatives, net

(17,885
)

(63,155
)
Cash settlements received for matured derivatives, net

65,937


63,141

Cash settlements received for early terminations of derivatives, net

80,000


—

Premiums paid for derivatives
 
(81,850
)

(1,421
)
Interest expense
 
23,705


32,414

Loss on disposal of assets, net

160


762

Adjusted EBITDA
 
$
96,076


$
118,562

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) impairment of oil and natural gas properties, (iv) revenue recognition, (v) estimation of income taxes, (vi) asset retirement obligations, (vii) valuation of derivatives and deferred premiums, (viii) valuation of stock-based compensation and performance unit compensation and (ix) fair value of assets acquired and liabilities assumed in an acquisition. 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 three months ended March 31, 2016. 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 2015 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.

51


Recent accounting pronouncements
See Note 18 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for information regarding recent accounting pronouncements.
Off-balance sheet arrangements
Currently, we do not have any off-balance sheet arrangements other than operating leases, drilling contracts and firm sale and transportation commitments, which are included in "Obligations and commitments." See Note 12 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information.

52


Item 3.    Quantitative and Qualitative Disclosures About Market Risk
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term "market risk," in our case, refers to the risk of loss arising from adverse changes in oil, 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 in oil, NGL and natural gas prices, we use derivatives, such as puts, swaps, collars and, in prior periods, basis swaps to hedge price risk associated with a significant portion of our anticipated production. By removing a portion 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 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 derivatives are largely determined by estimates of the forward curves of the relevant price indices. As of March 31, 2016, a 10% change in the forward curves associated with our derivatives would have changed our net positions to the following amounts:
(in thousands)
 
10% Increase
 
10% Decrease
Derivatives
 
$
193,960

 
$
271,550

As of March 31, 2016 and December 31, 2015, the fair values of our open derivative contracts were $230.0 million and $276.2 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 March 31, 2016, we had $195.0 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 March 31, 2016, as shown in the table below. 
 
 
Expected maturity date
 
 
(in millions except for interest rates)
 
2018
 
2022
 
2023
 
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
 
$
195.0

 
$
—

 
$
—

 
$
195.0

Average interest rate
 
1.944
%
 
—
%
 
—
%
 
1.944
%
Counterparty and customer credit risk
As of March 31, 2016, our principal exposures to credit risk are through receivables of (i) $230.2 million from the fair values of our open derivative contracts, (ii) $31.1 million from the sale of our oil, NGL and natural gas production that we market to energy marketing companies and refineries, (iii) $23.0 million from joint-interest partners, (iv) $18.1 million from matured derivatives and (v) $12.3 million from sales of purchased oil and other products.
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

53


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 11 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional disclosures regarding credit risk.

54


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 March 31, 2016. Our disclosure controls and other procedures are designed to provide reasonable assurance that the information required to be disclosed in the reports we file and submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to Laredo's management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.
Evaluation of changes in internal control over financial reporting
There were no changes in our internal control over financial reporting during the quarter ended March 31, 2016 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

55


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 2015 Annual Report. There have been no material changes in our risk factors from those described in the 2015 Annual Report. The risks described in the 2015 Annual Report are not the only risks facing us. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.

Item 2.    Repurchase of Equity Securities
Period
 
Total number of shares withheld(1)
 
Average price per share
 
Total number of shares purchased as part of publicly announced plans
 
Maximum number of shares that may yet be purchased under the plan
January 1, 2016 - January 31, 2016
 
1,954

 
$
7.59

 
—

 
—

February 1, 2016 - February 29, 2016
 
271,133

 
$
5.08

 
—

 
—

March 1, 2016 - March 31, 2016
 
3,130

 
$
7.00

 
—

 
—

Total
 
276,217

 
 
 
 
 
 
______________________________________________________________________________
(1)
Represents shares that were withheld by us to satisfy employee tax withholding obligations that arose upon the lapse of restrictions on restricted stock.
Item 3.    Defaults Upon Senior Securities

None.

Item 4.    Mine Safety Disclosures

Not applicable.

Item 5.    Other Information

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

56


The disclosure below relates solely to activities conducted by SAMIH and its 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 one or more SEC-reporting affiliates of SAMIAH intends to disclose in their next annual or quarterly SEC report that:
(a) Santander UK plc ("Santander UK") holds two frozen savings accounts and two frozen current accounts for three customers, resident in the U.K., who are currently designated by the U.S. under the Specially Designed Global Terrorist ("SDGT") sanctions program. The accounts held by each customer were blocked after the customer's designation and have remained blocked and dormant throughout the first quarter of 2016. Revenue generated by Santander UK on these accounts in the first quarter of 2016 was £3.67 whilst net profits in the first quarter of 2016 were negligible relative to the overall profits of Banco Santander, S.A.
(b) An Iranian national, resident in the U.K., who is currently designated by the U.S. under the Iranian Financial Sanctions Regulations ("IFSR") and the Weapons of Mass Destruction Proliferators Sanctions Regulations, 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 first quarter of 2016, total revenue generated by Santander UK in connection with the mortgage was £201.22 whilst net profits were negligible relative to the overall profits of Banco Santander, S.A. 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 ISA Managers Limited. The funds in both accounts are invested in the same portfolio fund. The accounts have remained frozen during the first quarter of 2016. The investment returns are being automatically reinvested, and no disbursements have been made to the customer. Total revenue in the first quarter of 2016 generated by Santander UK in connection with the investment accounts was £4.89 whilst net profits in the first quarter 2016 were negligible relative to the overall profits of Banco Santander, S.A.
(c) A U.K. national designated by the U.S. under the SDGT sanctions program holds a Santander UK current account. The account remained in arrears through the first quarter of 2016 (£1,344.01 in debt) and is currently being managed by Santander UK Collections & Recoveries department.
(d) In addition, during the first quarter of 2016, Santander UK has identified an OFAC match on a power of attorney account. A party listed on the account is currently designated by the U.S. under the SDGT and IFSR sanctions programs. During the first quarter of 2016, related revenue generated by Santander UK was £73.81 whilst net profits in the first quarter of 2016 were negligible relative to the overall profits of Banco Santander, S.A.

Item 1.01 Entry into a material definitive agreement

Effective May 2, 2016, in connection with the regular semi-annual redetermination of the borrowing base under our Senior Secured Credit Facility, we received the Memorandum of Borrowing Base Reduction attached hereto as Exhibit 10.1 from Wells Fargo Bank, N.A., the administrative agent under the Senior Secured Credit Facility, providing that the borrowing base and aggregate elected commitment amounts were each reduced to $815.0 million. This redetermined borrowing base shall remain in effect until the earlier of (i) the next scheduled semi-annual redetermination date or (ii) the date the borrowing base is otherwise adjusted pursuant to the terms of the Senior Secured Credit Facility. The other terms of the Senior Secured Credit Facility remain unchanged and are discussed in Note 5.e to our unaudited consolidated financial statements included elsewhere in this Quarterly Report and Note 5.f to our audited consolidated financials included in our 2015 Annual Report. As of May 4, 2016, the outstanding balance under the Senior Secured Credit Facility was $210.0 million.

The foregoing description of the Memorandum of Borrowing Base Reduction is a summary only and is qualified in its entirety by reference to the complete text of the Memorandum of Borrowing Base Reduction, a copy of which is attached as Exhibit 10.1 to this Quarterly Report and is incorporated herein by reference.


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.

57


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

 
Second Amended and Restated Bylaws of Laredo Petroleum, Inc. (incorporated by reference to Exhibit 3.3 of Laredo's Annual Report on Form 10-K (File No. 001-35380) filed on February 17, 2016).
 

 
 
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*

 
Memorandum of Borrowing Base Reduction, dated May 2, 2016, from Wells Fargo, Bank, N.A. to Laredo Petroleum, Inc.
 
 
 
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.



58


SIGNATURES
 
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. 
 
LAREDO PETROLEUM, INC.
 
 
 
Date: May 5, 2016
By:
/s/ Randy A. Foutch
 
 
Randy A. Foutch
 
 
Chairman and Chief Executive Officer
 
 
(principal executive officer)
 
 
 
Date: May 5, 2016
By:
/s/ Richard C. Buterbaugh
 
 
Richard C. Buterbaugh
 
 
Executive Vice President and Chief Financial Officer
 
 
(principal financial officer)
 
 
 
 
By:
 
Date: May 5, 2016
By:
/s/ Michael T. Beyer
 
 
Michael T. Beyer
 
 
Vice President - Controller and Chief Accounting Officer
 
 
(principal accounting officer)
 
 
 
 
 
 

59


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

 
Second Amended and Restated Bylaws of Laredo Petroleum, Inc. (incorporated by reference to Exhibit 3.3 of Laredo's Annual Report on Form 10-K (File No. 001-35380) filed on February 17, 2016).
 

 
 
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*

 
Memorandum of Borrowing Base Reduction, dated May 2, 2016, from Wells Fargo, Bank, N.A. to Laredo Petroleum, Inc.
 
 
 
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.



60

Laredo Petroleum, Inc. Reports